ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the combined and consolidated financial statements and the related notes thereto included elsewhere in this report. In this report, the terms “Spark Energy,” “Company,” “we,” “us” and “our” refer collectively to (i) the combined business and assets of the retail natural gas business and asset optimization activities of Spark Energy Gas, LLC and the retail electricity business of Spark Energy, LLC before the completion of our corporate reorganization in connection with the initial public offering of Spark Energy, Inc., which closed on August 1, 2014 (the “Offering”) and (ii) Spark Energy, Inc. and its subsidiaries as of the Offering and thereafter.
Overview
We are a growing independent retail energy services company first founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable-price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of December 31, 2014, we operated in 46 utility service territories across 16 states.
Our business consists of two operating segments:
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|
•
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Retail Natural Gas Segment
. We purchase natural gas supply through physical and financial transactions with market counterparts and supply natural gas to residential and commercial consumers pursuant to fixed-price, variable-price and flat-rate contracts. For the years ended December 31, 2014, 2013 and 2012, approximately 45%, 39% and 32%, respectively, of our retail revenues were derived from the sale of natural gas. We also identify wholesale natural gas arbitrage opportunities in conjunction with our retail procurement and hedging activities, which we refer to as asset optimization.
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|
|
•
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Retail Electricity Segment
. We purchase electricity supply through physical and financial transactions with market counterparts and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2014, 2013 and 2012, approximately 55%, 61% and 68%, respectively, of our retail revenues were derived from the sale of electricity.
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Spark Energy, Inc. was formed in April 2014 and only has historical financial operating results for the portions of the periods covered by this report that are subsequent to the closing of the Offering on August 1, 2014. The following discussion analyzes our historical combined financial condition and results of operations before the Offering, which is the combined businesses and assets of the retail natural gas business and asset optimization activities of Spark Energy Gas, LLC (“SEG”) and the retail electricity business of Spark Energy, LLC (“SE”) and the consolidated results of operations and financial condition of Spark Energy, Inc. and its subsidiaries after the Offering. SE and SEG are the operating subsidiaries through which we have historically operated our retail energy business and were commonly controlled by NuDevco Partners, LLC prior to the Offering.
Drivers of our Business
Customer Growth
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|
|
|
|
|
|
|
|
|
(In thousands)
|
Retail Electricity
|
Retail Natural Gas
|
Total
|
% Annual Increase (Decrease)
|
Customers at 12/31/2011
|
210
|
|
109
|
|
319
|
|
|
Additions
|
50
|
|
32
|
|
82
|
|
|
Attrition
|
118
|
|
46
|
|
164
|
|
|
Customers at 12/31/2012
|
142
|
|
95
|
|
237
|
|
(26
|
)%
|
Additions
|
34
|
|
31
|
|
65
|
|
|
Attrition
|
55
|
|
36
|
|
91
|
|
|
Customers at 12/31/2013
|
121
|
|
90
|
|
211
|
|
(11
|
)%
|
Additions
|
94
|
|
189
|
|
283
|
|
|
Attrition
|
70
|
|
106
|
|
176
|
|
|
Customers at 12/31/2014
|
145
|
|
173
|
|
318
|
|
51
|
%
|
Customer growth is a key driver of our operations. We attempt to grow our customer base by offering customers competitive pricing, price certainty or green product offerings. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price the local regulated utility is offering. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that satisfies our profitability objectives and provides customer value. We develop marketing campaigns using a combination of sales channels, with an emphasis on door-to-door marketing and outbound telemarketing given their flexibility and historical effectiveness. We identify and acquire customers through a variety of additional sales channels, including our inbound customer care call center, online marketing, email, direct mail, affinity programs, direct sales, brokers and consultants. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired growth and profitability targets.
Our 51% net customer growth in 2014 reflects the overall success of our marketing campaigns relaunched in the second half of 2013 that continued throughout 2014. Although we do not expect growth to continue at these levels, we are committed to growing and diversifying our customer base through changing market conditions. The 2014 growth was primarily organic but includes two acquisitions of customer contracts in Connecticut. See Note 14 to the Company’s audited combined and consolidated financial statements for a discussion of these acquisitions.
In 2012, our previous owner made the determination to invest excess cash flows from our operations in other affiliated businesses. As a result, we significantly reduced our spending on customer acquisition costs, including completely discontinuing some marketing channels, and focused our efforts on integrating and optimizing our existing expanded customer base. As such, our customer attrition out-paced additions and our customer count was reduced by 26%. In mid-2013, we began reactivating our marketing channels and reinvested in customer acquisitions. By late 2013 the customer book was increasing but ended 2013 down from 2012 by 11%.
Customer Acquisition Spending
|
|
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(In thousands)
|
Year Ended 12/31/14
|
Year Ended 12/31/13
|
Year Ended 12/31/12
|
Total Customer Acquisition Spending
|
$
|
26,191
|
|
$
|
8,257
|
|
$
|
6,322
|
|
Without Southern California
|
16,355
|
|
8,257
|
|
6,322
|
|
Management of customer acquisition costs is a key component to our profitability. We attempt to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods. We capitalize and amortize our customer acquisition costs over a two year period, which is based on the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition spending. Customer acquisition spending per customer in 2014 is in line with historical experience and management expectations.
We invested $9.8 million acquiring customers in Southern California in 2014, or approximately 37% of total customer acquisition costs of $26.2 million in 2014. Given the abnormally high early termination and disconnect for non-payment attrition rates we faced in this market, this expenditure yielded significantly less net customer growth than in our other markets. As a result, we have determined that a portion of our unamortized capitalized customer acquisition costs in Southern California in 2014 have been impaired, and we accelerated amortization of these costs by $6.5 million for the year ended December 31, 2014 to reflect the estimated future cash flows of the Southern California customer contracts.
The $16.4 million customer acquisition costs outside of Southern California were invested in acquiring gas and electricity customers across our various other markets with economics that met or exceeded our targeted return thresholds.
In 2012, our previous owner made the determination to invest excess cash flows from our operations in other affiliated businesses. As a result, we significantly reduced our spending on customer acquisition costs, including completely discontinuing some marketing channels, and focused our efforts on integrating and optimizing our existing expanded customer base. In mid-2013, we began reactivating our marketing channels and reinvested in customer acquisitions resulting in an increase in customer acquisition costs in 2013.
Our Ability to Manage Customer Attrition
|
|
|
|
|
|
|
|
|
Year Ended 12/31/14
|
Year Ended 12/31/13
|
Year Ended 12/31/12
|
Total Attrition
|
5.5
|
%
|
3.6
|
%
|
4.6
|
%
|
Without Southern California
|
4.8
|
%
|
3.6
|
%
|
4.6
|
%
|
Customer attrition is primarily due to: (i) customer initiated switches; (ii) residential moves and (iii) disconnection for customer payment defaults. Our rate of attrition during 2014 increased significantly due to higher than expected customer attrition in the Northeast due to extreme weather patterns experienced during the 2013-2014 winter season. Additionally, we saw high early tenure attrition and disconnects for non-payment in the Southern California gas market where we offered flat and fixed rate gas products in a largely unpenetrated and minimally competitive market. Finally, as expected, we experienced early tenure churn in several markets where we aggressively relaunched our marketing efforts in late 2013 and 2014. We anticipate first quarter 2015 attrition to remain at elevated levels before returning to more normal levels as the elevated levels of attrition in Southern California portfolio continue due primarily to disconnects for non-payment. See
“—
Southern California Market Entry
”
below for a more detailed discussion of our attrition rates in Southern California.
Customer attrition in 2013 was benefited by the minimal customer acquisition spending throughout 2012 and most of 2013 as early tenure attrition was negligible. However, the overall customer count continued to shrink until the marketing channels were relaunched in late 2013. Customer attrition in 2012 was slightly elevated compared to 2011 levels due to the large number of customer additions in 2011, when the customer base grew by approximately 63%, or 123,000 customers.
Customer Credit Risk
|
|
|
|
|
|
|
|
|
12/31/2014
|
12/31/2013
|
12/31/2012
|
Total Non-POR Bad Debt as % of Revenue
|
5.7
|
%
|
1.8
|
%
|
1.1
|
%
|
Total Non-POR Bad Debt as % of Revenue, excluding Southern California
|
3.2
|
%
|
1.8
|
%
|
1.1
|
%
|
In many of the utility service territories where we conduct business, purchase of receivables (“POR”) programs have been established, whereby the local regulated utility offers services for billing the customer, collecting payment from the customer and remitting payment to us. This service results in substantially all of our credit risk being linked to the applicable utility and not to our end-use customer in these territories. Approximately 44%, 47% and 55% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies as of December 31, 2014, 2013 and 2012, respectively, all of which had investment grade ratings as of such date. During the same periods, we paid these local regulated utilities a weighted average discount of approximately 1.0% of total revenues for customer credit risk protection. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.
In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit screening, deposits, disconnection for non-payment and collection efforts in the case of residential customers.
Our bad debt expense for the year ended December 31, 2014, 2013 and 2012 was approximately 5.7%, 1.8% and 1.1% of non-POR market retail revenues, respectively. Bad debt expense has increased in 2014 as a result of several factors, one of which was our focus on customer acquisition in the Southern California gas market in which we bear customer credit risk. A larger than anticipated percentage of new customers in this market have been terminating service between 30 and 90 days of coming on flow or have not been paying their invoices resulting in disconnect for non-payment, which has left the Company attempting to recoup one to three months of outstanding balances from these customers. Our ability to manage customer credit risk in this market is primarily through disconnection and aggressive collection efforts. See
“—
Southern California Market Entry
” below.
Bad debt expense attributable to the Northeast Region has also increased in 2014 as we have experienced greater difficulty in collecting higher than normal bills from commercial and residential customers following the extreme weather patterns in that region during the 2014 winter season.
We recorded accounts receivable, net of allowance, for non-POR markets of $24.6 million and $24.8 million for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014 and 2013, we had recorded accounts receivable, net of allowance, of $0.9 million and zero for Southern California.
Our bad debt expense in 2013 and 2012 was in line with industry averages and primarily resulted from Texas, which was our largest non-POR market during both years.
Southern California Market Entry
The Company’s results for 2014 were negatively impacted by our market entry into Southern California. Starting in the second quarter of 2014 we accelerated our growth by acquiring carbon neutral gas customers in Southern California. Although we were successful in our acquisition of customers, the campaign faced significant challenges. These challenges resulted in higher than estimated customer attrition and bad debt expense. We attribute our high customer
attrition and non-payment rates in the Southern California gas market to confusion and lack of awareness by consumers in an early stage competitive market that is also a “dual bill” market for which customers receive two bills, one from the local distribution utility for delivery and one from the retail energy provider for the product. These factors were exacerbated by the lack of an immediate savings from the utility price as the products that we are offering provided carbon natural gas at a neutral fixed price rather than an immediate savings claim. As a result, our monthly attrition in the Southern California gas market averaged 11.4% during the time we were actively marketing there (April 2014 to December 2014), as compared to an average attrition rate of 4.8% for the rest of the Company’s markets during 2014. Our bad debt expense in this market is heavily impacted by early stage customer attrition and non-payment rates. As noted above, a much larger than anticipated percentage of new customers in this market terminated or had their services disconnected for non-payment between 30 and 90 days of coming on flow which has left the Company attempting to recoup one to three months of outstanding balances from these customers. Our ability to manage customer credit risk in this market is primarily through disconnection and aggressive collection efforts. Our bad debt expense in the Southern California gas market during 2014 was $4.8 million, or an average of 51.0%, as compared to $5.4 million, or an average of 3.2%, for all other markets.
During the third quarter, we began responding to the initial negative results in the Southern California gas market by reducing customer acquisition spending in this market, revamping our products, renegotiating our compensation structure with our primary sales vendor, and increasing our efforts to train the vendor and educate the customer, all with the goal of improving the overall economics for this market. By the end of the third quarter, we had significantly reduced customer acquisition spending as the mitigation efforts taken in the quarter were not providing the desired results. In the fourth quarter, we took further steps to reduce our sales in Southern California, such that we substantially ceased marketing efforts by the end of the year. We continue to focus our efforts on aggressive collection initiatives. We invested $9.8 million acquiring customers in Southern California in 2014, or approximately 37% of total customer acquisition spending of $26.2 million in 2014. We have determined that a portion of our unamortized customer acquisition costs in Southern California in 2014 has been impaired, resulting in accelerated amortization of these costs of $6.5 million during the year ended December 31, 2014. Additionally, although marketing efforts in Southern California substantially ceased by the end of 2014, new customers continue to come on-flow in the first quarter of 2015. We anticipate attrition and bad debt expense to remain high during the first quarter of 2015 as a result of these issues.
Weather Conditions
Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms. We are particularly sensitive to this variability because of our current substantial concentration and focus on growth in the residential customer segment in which energy usage is highly sensitive to weather conditions that impact heating and cooling demand. The extreme weather patterns during the 2013 and 2014 winter season caused commodity demand and prices to rise significantly beyond industry forecasts. As a result, the retail energy industry generally charged higher prices to its variable-price customers resulting in increased attrition and bad debt expense and was subject to decreased margins on fixed-price contracts due to unanticipated increases in volumetric demand that had to be purchased in the spot market at high prices. Our results during the first quarter of 2014 suffered as a result of this severe weather abnormality. After the first quarter 2014 extreme weather conditions, our major markets returned to historical norms for the remainder of the year.
Asset Optimization
Our natural gas business includes opportunistic transactions in the natural gas wholesale marketplace in conjunction with our retail procurement and hedging activities. Asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is the highest. As such, the majority of our asset optimization profits are made in the winter. Given the opportunistic nature of these activities we experience variability in our earnings from our asset optimization activities from year to year. As these activities are accounted for using mark-to-market accounting, the timing of our revenue recognition often differs from the actual cash settlement.
During 2014, we were obligated to pay demand charges of approximately $2.8 million under certain long-term legacy transportation assets that our predecessor entity acquired prior to 2013. Although these demand payments will decrease over time, the related capacity agreements extend through 2028. Net asset optimization results were a gain of $2.3 million, a gain of $0.3 million and a loss of $1.1 million for the year ended December 31, 2014, 2013 and 2012, respectively, primarily due to arbitrage opportunities we captured during the extreme weather pattern in the Northeast during the first quarter offset by our legacy capacity charges.
Factors Affecting Comparability of Historical Financial Results
Tax Receivable Agreement.
The Tax Receivable Agreement between us and NuDevco Retail Holdings, LLC, NuDevco Retail, LLC and Spark HoldCo provides for the payment by Spark Energy, Inc. to NuDevco Retail Holdings of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that Spark Energy, Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the Offering as a result of (i) any tax basis increases resulting from the purchase by Spark Energy, Inc. of Spark HoldCo units from NuDevco Retail Holdings prior to or in connection with the Offering, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the exchange right set forth in the limited liability company agreement of Spark HoldCo (or resulting from an exchange of Spark HoldCo units for cash under the Spark HoldCo limited liability agreement) and (iii) any imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. We have recorded 85% of the estimated tax benefit as an increase to amounts payable under the Tax Receivable Agreement as a liability. We will retain the benefit of the remaining 15% of these tax savings.
Executive Compensation Programs.
On August 1, 2014, we granted restricted stock units to our employees, non-employee directors, and certain employees of our affiliates who perform services for us under our long-term incentive plan. The initial restricted stock unit awards generally vest ratably over approximately one, three or four years commencing May 4, 2015 and include tandem dividend equivalent rights that will vest upon the same schedule as the underlying restricted stock unit.
Financing.
The total amounts outstanding under our Seventh Amended Credit Agreement as of December 31, 2013 and until the Offering included amounts used to fund equity distributions to our common control owner to fund operations of an affiliated company. As such, historical borrowings under our Seventh Amended Credit Agreement may not provide an accurate indication of what we need to operate our natural gas and electricity business. Concurrently with the closing of the Offering, we entered into a new
$70.0 million
Senior Credit Facility, and the Seventh Amended Credit Agreement was terminated.
How We Evaluate Our Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
2014
|
|
2013
|
|
2012
|
Adjusted EBITDA
|
$
|
11,324
|
|
|
$
|
33,533
|
|
|
$
|
40,659
|
|
Retail Gross Margin
|
$
|
76,944
|
|
|
$
|
81,668
|
|
|
$
|
93,219
|
|
Adjusted EBITDA
. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, (ii) net gain (loss) on derivative instruments, and (iii) net current period cash settlements on derivative instruments, plus (iv) non-cash compensation expense and (v) other non-cash operating items. EBITDA is defined as net income (loss) before provision for income taxes, interest expense and depreciation and amortization. We deduct all current period customer acquisition costs in the Adjusted EBITDA calculation because such costs reflect a cash outlay in the year in which they are incurred, even though we capitalize such costs and amortize them over two years in accordance with our accounting policies. The deduction of current period customer acquisition costs is consistent with how we manage our business, but the comparability of Adjusted EBITDA between periods may be affected by varying levels of customer acquisition costs. For example, our Adjusted EBITDA is lower in years of customer growth reflecting larger customer acquisition spending. We deduct our net gains (losses) on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on derivative instruments. We also deduct non-cash compensation expense as a result of restricted stock units that are issued under our long-term incentive plan.
We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our liquidity and financial condition and results of operations and that Adjusted EBITDA is also useful to investors as a financial indicator of a company’s ability to incur and service debt, pay dividends and fund capital expenditures. Adjusted EBITDA is a supplemental financial measure that management and external users of our combined and consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:
|
|
•
|
our operating performance as compared to other publicly traded companies in the retail energy industry, without regard to financing methods, capital structure or historical cost basis;
|
|
|
•
|
the ability of our assets to generate earnings sufficient to support our proposed cash dividends; and
|
|
|
•
|
our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt.
|
Retail Gross Margin.
We define retail gross margin as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (i) net asset optimization revenues, (ii) net gains (losses) on non-trading derivative instruments, and (iii) net current period cash settlements on non-trading derivative instruments. Retail gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity business by removing the impacts of our asset optimization activities and net non-cash income (loss) impact of our economic hedging activities. As an indicator of our retail energy business’ operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP.
The GAAP measures most directly comparable to Adjusted EBITDA are net income (loss) and net cash provided by operating activities. The GAAP measure most directly comparable to Retail Gross Margin is operating income (loss). Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net income (loss), net cash provided by operating activities, or operating income (loss). Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have important limitations as analytical tools. You should not consider Adjusted EBITDA or Retail Gross Margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Retail Gross Margin exclude some, but not all, items that affect net income (loss) and net cash provided by operating activities,
and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.
Management compensates for the limitations of Adjusted EBITDA and Retail Gross Margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
The following table presents a reconciliation of Adjusted EBITDA to net (loss) income for each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
2014
|
|
2013
|
|
2012
|
Reconciliation of Adjusted EBITDA to Net (Loss) Income:
|
|
|
|
|
|
Net (loss) income
|
$
|
(4,265
|
)
|
|
$
|
31,412
|
|
|
$
|
26,093
|
|
Depreciation and amortization
|
22,221
|
|
|
16,215
|
|
|
22,795
|
|
Interest expense
|
1,578
|
|
|
1,714
|
|
|
3,363
|
|
Income tax expense
|
(891
|
)
|
|
56
|
|
|
46
|
|
EBITDA
|
18,643
|
|
|
49,397
|
|
|
52,297
|
|
Less:
|
|
|
|
|
|
Net, Gains (losses) on derivative instruments
|
(14,535
|
)
|
|
6,567
|
|
|
(21,485
|
)
|
Net, Cash settlements on derivative instruments
|
(3,479
|
)
|
|
1,040
|
|
|
26,801
|
|
Customer acquisition costs
|
26,191
|
|
|
8,257
|
|
|
6,322
|
|
Plus:
|
|
|
|
|
|
Non-cash compensation expense
|
858
|
|
|
—
|
|
|
—
|
|
Adjusted EBITDA
|
$
|
11,324
|
|
|
$
|
33,533
|
|
|
$
|
40,659
|
|
The following table presents a reconciliation of Adjusted EBITDA to net cash provided by operating activities for each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
2014
|
|
2013
|
|
2012
|
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
|
|
|
|
|
|
Net cash provided by operating activities
|
$
|
5,874
|
|
|
$
|
44,480
|
|
|
$
|
44,076
|
|
Amortization and write off of deferred financing costs
|
(631
|
)
|
|
(678
|
)
|
|
(919
|
)
|
Allowance for doubtful accounts and bad debt expense
|
(10,164
|
)
|
|
(3,101
|
)
|
|
(1,835
|
)
|
Interest expense
|
1,578
|
|
|
1,714
|
|
|
3,363
|
|
Income tax (benefit) expense
|
(891
|
)
|
|
56
|
|
|
46
|
|
Changes in operating working capital
|
|
|
|
|
|
Accounts receivable, prepaids, current assets
|
13,332
|
|
|
(17,790
|
)
|
|
(12,737
|
)
|
Inventory
|
3,711
|
|
|
599
|
|
|
(3,442
|
)
|
Accounts payable and accrued liabilities
|
(2,466
|
)
|
|
7,879
|
|
|
12,689
|
|
Other
|
981
|
|
|
374
|
|
|
(582
|
)
|
Adjusted EBITDA
|
$
|
11,324
|
|
|
$
|
33,533
|
|
|
$
|
40,659
|
|
The following table presents a reconciliation of Retail Gross Margin to operating (loss) income for each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
2014
|
|
2013
|
|
2012
|
Reconciliation of Retail Gross Margin to Operating (Loss) Income:
|
|
|
|
|
|
Operating (loss) income
|
$
|
(3,841
|
)
|
|
$
|
32,829
|
|
|
$
|
29,440
|
|
Depreciation and amortization
|
22,221
|
|
|
16,215
|
|
|
22,795
|
|
General and administrative
|
45,880
|
|
|
35,020
|
|
|
47,321
|
|
Less:
|
|
|
|
|
|
Net asset optimization revenue
|
2,318
|
|
|
314
|
|
|
(1,136
|
)
|
Net, Gains (losses) on non-trading derivative instruments
|
(8,713
|
)
|
|
1,429
|
|
|
(19,016
|
)
|
Net, Cash settlements on non-trading derivative instruments
|
(6,289
|
)
|
|
653
|
|
|
26,489
|
|
Retail Gross Margin
|
$
|
76,944
|
|
|
$
|
81,668
|
|
|
$
|
93,219
|
|
Combined and Consolidated Results of Operations
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
In Thousands
|
Year Ended December 31,
|
|
|
|
2014
|
|
2013
|
|
Change
|
Revenues:
|
|
|
|
|
|
|
Retail revenues
|
$
|
320,558
|
|
|
$
|
316,776
|
|
|
$
|
3,782
|
|
Net asset optimization revenues
|
2,318
|
|
|
314
|
|
|
2,004
|
|
Total Revenues
|
322,876
|
|
|
317,090
|
|
|
5,786
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
Retail cost of revenues
|
258,616
|
|
|
233,026
|
|
|
25,590
|
|
General and administrative
|
45,880
|
|
|
35,020
|
|
|
10,860
|
|
Depreciation and amortization
|
22,221
|
|
|
16,215
|
|
|
6,006
|
|
Total Operating Expenses
|
326,717
|
|
|
284,261
|
|
|
42,456
|
|
Operating (loss) income
|
(3,841
|
)
|
|
32,829
|
|
|
(36,670
|
)
|
Other (expense)/income:
|
|
|
|
|
|
|
|
|
Interest expense
|
(1,578
|
)
|
|
(1,714
|
)
|
|
136
|
|
Interest and other income
|
263
|
|
|
353
|
|
|
(90
|
)
|
Total other (expenses)/income
|
(1,315
|
)
|
|
(1,361
|
)
|
|
46
|
|
(Loss) income before income tax expense
|
(5,156
|
)
|
|
31,468
|
|
|
(36,624
|
)
|
Income tax (benefit) expense
|
(891
|
)
|
|
56
|
|
|
(947
|
)
|
Net (loss) income
|
$
|
(4,265
|
)
|
|
$
|
31,412
|
|
|
$
|
(35,677
|
)
|
Adjusted EBITDA
(1)
|
$
|
11,324
|
|
|
$
|
33,533
|
|
|
$
|
(22,209
|
)
|
Retail Gross Margin
(1)
|
$
|
76,944
|
|
|
$
|
81,668
|
|
|
$
|
(4,724
|
)
|
Customer Acquisition Costs
|
$
|
26,191
|
|
|
$
|
8,257
|
|
|
$
|
17,934
|
|
Customer Attrition
|
5.5%
|
|
|
3.6%
|
|
|
1.9%
|
|
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders
|
$
|
3,305
|
|
|
$
|
—
|
|
|
$
|
3,305
|
|
(1)
Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “How We Evaluate Our Operations” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable financial measures presented in accordance with GAAP.
Total Revenues.
Total revenues for the
year ended
December 31, 2014
were approximately
$322.9 million
, an increase of approximately
$5.8 million
, or
2%
, from approximately
$317.1 million
for the
year ended
December 31, 2013
. This increase was primarily due to overall higher customer pricing across both commodities, in part due to increased supply costs, which resulted in an increase in total revenues of $38.1 million, as well as a $2.0 million increase in net asset optimization revenues. This increase was offset by a decrease of $34.3 million due to customer sales volumes which were lower, primarily due to the shift of the concentration of our marketing efforts from commercial customers to residential customers.
Net Asset Optimization Revenues
. Net asset optimization revenues for the
year ended
December 31, 2014
were approximately
$2.3 million
, an increase of approximately
$2.0 million
, or
667%
, from
$0.3 million
in the prior year. This increase was primarily due to physical gas arbitrage opportunities in the Northeast that arose due to extreme winter weather conditions in 2014 and losses we recognized in 2013 from a hedge strategy involving interruptible transportation that did not repeat in 2014.
Retail Cost of Revenues
. Total retail cost of revenues for the
year ended
December 31, 2014
was approximately
$258.6 million
, an increase of approximately
$25.6 million
, or
11%
, from approximately
$233.0 million
for the
year ended
December 31, 2013
. This increase was primarily due to increased supply costs arising from capacity constraints from the extreme weather conditions in the Northeast during the first quarter of 2014, which resulted in an increase of total retail cost of revenues of $35.6 million, as well as an increase of $17.0 million due to a change in the value of our non-trading derivative portfolio used for hedging. This increase was offset by a decrease of $27.0 million due to customer sales volumes which were lower, primarily due to the strategic shift of the concentration of our marketing efforts from commercial customers to residential customers.
General and Administrative Expense
. General and administrative expense for the
year ended
December 31, 2014
was approximately
$45.9 million
, an increase of approximately
$10.9 million
, or
31%
, as compared to
$35.0 million
for the
year ended
December 31, 2013
. This increase was primarily due to an increase of bad debt expense of $7.1 million, which was $10.2 million for the year ended December 31, 2014 compared to $3.1 million for the year ended December 31, 2013, as well as increased costs associated with being a public company and increased billing and other variable costs associated with increased customers.
Depreciation and Amortization Expense
. Depreciation and amortization expense for the
year ended
December 31, 2014
was approximately
$22.2 million
, an increase of approximately
$6.0 million
, or
37%
, from approximately
$16.2 million
for the
year ended
December 31, 2013
. This increase was primarily due to the accelerated amortization of capitalized customer acquisition costs in Southern California and Massachusetts of $6.5 million and $0.2 million, respectively, in the fourth quarter of 2014 offset by lower depreciation for certain software assets that were fully depreciated in 2013.
Customer Acquisition Cost
. Customer acquisition cost for the year ended December 31, 2014 was approximately
$26.2 million
, an increase of approximately $17.9 million from approximately $8.3 million for the
year ended
December 31, 2013
. This increase was due to our increased marketing efforts to grow our customer base beginning in the second half of 2013 and continuing during 2014 including spending in California of $15.4 million, spending in Illinois of $6.4 million and spending in New York for $1.1 million for the year ended December 31, 2014.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
In Thousands
|
Year Ended December 31,
|
|
|
|
2013
|
|
2012
|
|
Change
|
Revenues:
|
|
|
|
|
|
Retail revenues
|
$
|
316,776
|
|
|
$
|
380,198
|
|
|
$
|
(63,422
|
)
|
Net asset optimization revenues
|
314
|
|
|
(1,136
|
)
|
|
1,450
|
|
Total Revenues
|
317,090
|
|
|
379,062
|
|
|
(61,972
|
)
|
Operating Expenses:
|
|
|
|
|
|
Retail cost of revenues
|
233,026
|
|
|
279,506
|
|
|
(46,480
|
)
|
General and administrative
|
35,020
|
|
|
47,321
|
|
|
(12,301
|
)
|
Depreciation and amortization
|
16,215
|
|
|
22,795
|
|
|
(6,580
|
)
|
Total Operating Expenses
|
284,261
|
|
|
349,622
|
|
|
(65,361
|
)
|
Operating (loss) income
|
32,829
|
|
|
29,440
|
|
|
3,389
|
|
Other (expense)/income:
|
|
|
|
|
|
Interest expense
|
(1,714
|
)
|
|
(3,363
|
)
|
|
1,649
|
|
Interest and other income
|
353
|
|
|
62
|
|
|
291
|
|
Total other (expenses)/income
|
(1,361
|
)
|
|
(3,301
|
)
|
|
1,940
|
|
(Loss) income before income tax expense
|
31,468
|
|
|
26,139
|
|
|
5,329
|
|
Income tax expense
|
56
|
|
|
46
|
|
|
10
|
|
Net (loss) income
|
$
|
31,412
|
|
|
$
|
26,093
|
|
|
$
|
5,319
|
|
Adjusted EBITDA
(1)
|
$
|
33,533
|
|
|
$
|
40,659
|
|
|
$
|
(7,126
|
)
|
Retail Gross Margin
(1)
|
$
|
81,668
|
|
|
$
|
93,219
|
|
|
$
|
(11,551
|
)
|
Customer Acquisition Costs
|
$
|
8,257
|
|
|
$
|
6,322
|
|
|
$
|
1,935
|
|
Customer Attrition
|
3.6%
|
|
|
4.6%
|
|
|
(1.0)%
|
|
(1)
Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “How We Evaluate Our Operations” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable financial measures presented in accordance with GAAP.
Total Revenues.
Total revenues for the year ended December 31, 2013 were approximately $317.1 million, a decrease of approximately $62.0 million, or 16%, from approximately $379.1 million for the year ended December 31, 2012. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease in total revenues of $89.2 million. This decrease was offset by an increase of total revenues of $25.7 million due to increased customer pricing and a $1.5 million increase in net asset optimization revenues.
Net Asset Optimization Revenues
. Net asset optimization revenues for the year ended December 31, 2013 were approximately $0.3 million, an increase of approximately $1.4 million, or 128%, from $(1.1) million in the same period in the prior year. We recognized losses in late 2012 and early 2013 on a hedge strategy involving interruptible transportation, partially offset by increased arbitrage opportunities in the fourth quarter of 2013 in the northeast United States.
Retail Cost of Revenues
. Total retail cost of revenues for the year ended December 31, 2013 was approximately $233.0 million, a decrease of approximately $46.5 million, or 17%, from approximately $279.5 million for the year ended December 31, 2012. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease in total retail cost of revenues of $70.0 million. This decrease was offset by an increase of total retail cost of revenues of $18.1 million due to energy supply prices and a $5.4 million decrease in net gains on non-trading derivative instruments, net of cash settlements.
General and Administrative Expense
. General and administrative expense for the year ended December 31, 2013 was approximately $35.0 million, a decrease of approximately $12.3 million or 26%, as compared to $47.3 million
for the year ended December 31, 2012. Approximately $8.0 million of the decrease in our general and administrative expenses was due to a companywide initiative to reduce costs and realize operational efficiencies in conjunction with our shift in focus from increasing our customer base to optimizing our customer base. Additionally, approximately $2.7 million was attributable to a decrease in sales and marketing expenses.
Depreciation and Amortization Expense
. Depreciation and amortization expense for the year ended December 31, 2013 was approximately $16.2 million, a decrease of approximately $6.6 million, or 29%, from approximately $22.8 million in the same period in the prior year. This decrease was primarily due to the amortization in 2011 of a portion of higher customer acquisition costs that were incurred in 2011.
Interest Expense
. Interest expense for the year ended December 31, 2013 was approximately $1.7 million, a decrease of approximately $1.7 million, or 50%, from approximately $3.4 million in the same period in the prior year. This decrease was primarily due to reduced interest expense due to lower average borrowing amounts during the year as a result of reduced customer acquisition expenses in connection with the strategic initiative to optimize our customer base in 2012 discussed above.
Customer Acquisition Cost.
Customer acquisition cost for the year ended December 31, 2013 was approximately $8.3 million, an increase of approximately $2.0 million, or 31%, from approximately $6.3 million in the prior year. This increase was primarily due to increasing our marketing efforts during the second half of 2013 to grow our customer base.
Operating Segment Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
|
2012
|
|
(in millions, except volume and per unit operating data)
|
Retail Natural Gas Segment
|
|
|
|
|
|
Total Revenues
|
$
|
146.5
|
|
|
$
|
125.2
|
|
|
$
|
122.7
|
|
Retail Cost of Revenues
|
109.2
|
|
|
83.1
|
|
|
77.0
|
|
Less: Net Asset Optimization Revenues
|
2.3
|
|
|
0.3
|
|
|
(1.1
|
)
|
Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
|
(9.3
|
)
|
|
(0.6
|
)
|
|
6.3
|
|
Retail Gross Margin-Gas
|
$
|
44.3
|
|
|
$
|
42.4
|
|
|
$
|
40.5
|
|
Volumes-Gas (MMBtu's)
|
15,724,708
|
|
|
16,598,751
|
|
|
17,527,252
|
|
Retail Gross Margin-Gas per MMBtu
|
$
|
2.82
|
|
|
$
|
2.55
|
|
|
$
|
2.31
|
|
Retail Electricity Segment
|
|
|
|
|
|
Total Revenues
|
$
|
176.4
|
|
|
$
|
191.9
|
|
|
$
|
256.4
|
|
Retail Cost of Revenues
|
149.5
|
|
|
149.9
|
|
|
202.5
|
|
Less: Net Gains (Losses) on non-trading derivatives, net of cash settlements
|
(5.7
|
)
|
|
2.7
|
|
|
1.2
|
|
Retail Gross Margin—Electricity
|
$
|
32.6
|
|
|
$
|
39.3
|
|
|
$
|
52.7
|
|
Volumes - Electricity (MWh's)
|
1,526,652
|
|
|
1,829,657
|
|
|
2,698,084
|
|
Retail Gross Margin—Electricity per MWh
|
$
|
21.37
|
|
|
$
|
21.48
|
|
|
$
|
19.55
|
|
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Retail Natural Gas Segment
Retail revenues for the Retail Natural Gas Segment for the year ended December 31, 2014 were approximately $146.5 million, an increase of approximately $21.3 million, or 17%, from approximately $125.2 million for the year ended December 31, 2013. This increase was primarily due to higher customer pricing implemented in part to capture increased supply costs, which resulted in an increase of $21.9 million, as well as a $2.0 million increase in net optimization revenues. This increase was offset by a decrease of $2.6 million due to decreased customer sales volumes.
Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2014 were approximately $109.2 million, an increase of approximately $26.1 million, or 31%, from approximately $83.1 million for the year ended December 31, 2013. This increase was primarily due to increased supply costs resulting from the extreme weather conditions experienced across the United States during the first quarter of 2014, which resulted in an increase of $19.2 million, as well as a $8.6 million increase due to a change in the value of our non-trading derivative portfolio used for hedging. This increase was offset primarily by a $1.7 million decrease due to decreased customer sales volumes.
Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2014 was approximately $44.3 million, an increase of approximately $1.9 million, or 4%, as compared to $42.4 million for the year ended December 31, 2013, as indicated in the table below (in millions).
|
|
|
|
|
Increase in unit margin per MMBtu
|
$
|
2.9
|
|
Decrease in volumes sold
|
(1.0
|
)
|
Decrease in retail natural gas segment retail gross margin
|
$
|
1.9
|
|
The volumes of natural gas sold decreased from 16,598,751 MMBtu for the year ended December 31, 2013 to 15,724,708 MMBtu for the year ended December 31, 2014. This decrease was primarily due to the shift in our customer base to lower volume, higher margin residential gas users, primarily in Southern California.
Retail Electricity Segment
Retail revenues for the Retail Electricity Segment for the year ended December 31, 2014 were approximately $176.4 million, a decrease of approximately $15.5 million, or 8%, from approximately $191.9 million for the year ended December 31, 2013. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease of $31.7 million. This decrease was offset by an increase of retail revenues of $16.2 million due to higher customer pricing implemented in part to capture increased supply costs.
Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2014 were approximately $149.5 million, a decrease of approximately $0.4 million, or 0%, from approximately $149.9 million for the year ended December 31, 2013. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease of approximately $25.1 million. This decrease was offset by increased supply costs resulting from the extreme weather conditions experienced across the United States during the first quarter of 2014, which resulted in an increase in retail cost of revenues of $16.4 million, as well as an $8.3 million increase due to a change in the value of our non-trading derivative portfolio used for hedging.
Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2014 was approximately $32.6 million, a decrease of approximately $6.7 million, or 17%, as compared to $39.3 million for the year ended December 31, 2013, as indicated in the table below (in millions).
|
|
|
|
|
Decrease in unit margin per MWh
|
$
|
(0.2
|
)
|
Decrease in volumes sold
|
(6.5
|
)
|
Decrease in retail electricity segment retail gross margin
|
$
|
(6.7
|
)
|
The volumes of electricity sold decreased from 1,829,657 MWh for the year ended December 31, 2013 to 1,526,652 MWh for the year ended December 31, 2014. This decrease was primarily due to a decreased focus on higher volume but lower margin commercial customers. Electric unit margins expanded in 2014 with our shift to higher margin residential customers but were negatively impacted by the increased supply cost during the extreme weather patterns in the first quarter.
Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
Retail Natural Gas Segment
Retail revenues for the Retail Natural Gas Segment for the year ended December 31, 2013 were approximately $125.2 million, an increase of approximately $2.5 million, or 2%, from approximately $122.7 million in the prior year. This increase was primarily due to increased customer pricing, which resulted in an increase of $7.6 million, as well as an increase of $1.5 million due to net asset optimization revenue. This increase was offset by a decrease of $6.6 million due to lower customer sales volumes.
Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2013 was approximately $83.1 million, an increase of approximately $6.1 million, or 8%, from approximately $77.0 million in the prior year. This increase was primarily due to a $6.9 million decrease in the value of our non-trading derivative portfolio used for hedging, as well as increased commodity prices, which resulted in an increase of $3.6 million. This increase was offset by a decrease of retail cost of revenues of $4.4 million due to lower customer sales volumes.
Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2013 was approximately $42.4 million, an increase of approximately $1.9 million, or 5%, from approximately $40.5 million for the year ended December 31, 2012, as indicated in the table below (in millions).
|
|
|
|
|
Increase in unit margin per MMBtu
|
$
|
4.0
|
|
Decrease in volumes sold
|
(2.1
|
)
|
Increase in retail natural gas segment retail gross margin
|
$
|
1.9
|
|
The volumes of natural gas sold decreased from 17,527,252 MMBtu during the year ended December 31, 2012 to 16,598,751 MMBtu during the year ended December 31, 2013, due to our natural gas customer attrition outpacing natural gas customer acquisition attributable to the shift in our strategic focus, coupled with a decreased focus on higher-volume but lower margin commercial customers.
Retail Electricity Segment
Retail revenues for the Retail Electricity Segment for the year ended December 31, 2013 were approximately $191.9 million, a decrease of approximately $64.5 million, or 25%, from approximately $256.4 million in the prior year. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease of $82.5 million. This decrease was offset by an increase of retail revenues of $18.0 million due to increased customer pricing.
Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2013 was approximately $149.9 million, a decrease of approximately $52.6 million, or 26%, from approximately $202.5 million in the prior year. This decrease was primarily due to lower customer sales volumes, which resulted in a decrease in retail cost of revenues of $65.6 million and a $1.5 million increase in the value of our non-trading derivative portfolio used for hedging. This decrease was offset by an increase of retail cost of revenues of $14.5 million due to increased commodity prices.
Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2013 was approximately $39.3 million, a decrease of approximately $13.4 million, or 25%, as compared to $52.7 million for the year ended December 31, 2012, as indicated in the table below (in millions).
|
|
|
|
|
Increase in unit margin per MWh
|
$
|
3.6
|
|
Decrease in volumes sold
|
(17.0
|
)
|
Decrease in retail electricity segment retail gross margin
|
$
|
(13.4
|
)
|
The volumes of electricity sold decreased from 2,698,084 MWh during the year ended December 31, 2012 to 1,829,657 MWh during the year ended December 31, 2013, due to our electricity customer attrition outpacing electricity customer acquisition attributable to the shift in our strategic focus, coupled with a decreased focus on higher-volume but lower margin commercial customers.
Liquidity and Capital Resources
Our liquidity requirements fluctuate with our customer acquisition cost spending level, acquisitions, collateral posting requirements on our hedge portfolio, distributions, the effects of the timing between payments of payables and receipt of receivables, including bad debt receivables, and our general working capital needs for ongoing operations. Our credit facility borrowings are also subject to material variations on a seasonal basis due to the timing of commodity purchases to satisfy required natural gas inventory purchases and to meet customer demands during periods of peak usage. Moreover, estimating our liquidity requirements is highly dependent on then-current market conditions, including forward prices for natural gas and electricity, and market volatility.
Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. We believe that cash generated from these sources will be sufficient to sustain operations, to finance anticipated expansion plans and growth initiatives, and to pay required taxes and quarterly cash distributions. However, in the event our liquidity is insufficient, we may be required to limit our spending on future growth or other business opportunities or to rely on external financing sources, including additional commercial bank borrowings and the issuance of debt and additional equity securities, to fund our growth.
Based upon our current plans, level of operations and business conditions, we believe that our cash on hand, cash generated from operations, and available borrowings under our credit facility will be sufficient to meet our capital requirements and working capital needs for the foreseeable future.
The following table details our total liquidity as of the period presented:
|
|
|
|
|
|
December 31,
|
($ in thousands)
|
2014
|
Cash and cash equivalents
|
$
|
4,359
|
|
Senior Credit Facility Availability
(1)
|
26,260
|
|
Total Liquidity
|
$
|
30,619
|
|
(1)
Subject to Senior Credit Facility borrowing base restrictions.
Capital expenditure in 2014 included approximately
$26.2 million
on customer acquisitions and $3.0 million related to information systems improvements, including $2.0 million related to our outsourced customer information system.
The Spark HoldCo, LLC Agreement provides, to the extent cash is available, for distributions pro rata to the holders of Spark HoldCo units such that we receive an amount of cash sufficient to cover the estimated taxes payable by us, the targeted quarterly dividend we intend to pay to holders of our Class A common stock, and payments under the
Tax Receivable Agreement we have entered into with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail.
We paid a regular quarterly dividend on our Class A common stock of $0.3625 per share in 2014, or approximately $1.45 per share or $4.4 million on an annualized basis, which was prorated from the Offering date of August 1, 2014 for the third quarter 2014 dividend. No dividends on our Class A common stock will accrue in arrears. Our ability to pay dividends in the future will depend on many factors, including the performance of our business in the future and restrictions under our new Senior Credit Facility. In order to pay these dividends to holders of our Class A common stock and corresponding distributions to holders of our Class B common stock, we expect that Spark HoldCo will be required to distribute approximately $19.9 million on an annualized basis to holders of Spark HoldCo units. If our business does not generate enough cash for Spark HoldCo to make such distributions, we may have to borrow to pay our dividend. If our business generates cash in excess of the amounts required to pay an annual dividend of $1.45 per share of Class A common stock, we currently expect to reinvest any such excess cash flows in our business and not increase the distributions payable to holders of our Class A common stock. However, our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including the results of our operations, our financial condition, capital requirements and investment opportunities. On November 11, 2014, our Board of Directors declared a quarterly dividend for the third quarter of 2014 to holders of the Class A common stock on November 28, 2014. This dividend was paid on December 15, 2014. On February 16, 2015, our Board of Directors declared a quarterly dividend for the fourth quarter of 2014 to holders of the Class A common stock of record on March 2, 2015. This dividend will be paid on March 16, 2014.
In addition, we expect to make payments pursuant to the Tax Receivable Agreement that we have entered into with NuDevco Retail Holdings, NuDevco Retail and Spark HoldCo in connection with the Offering. Except in cases where we elect to terminate the Tax Receivable Agreement early (the Tax Receivable Agreement is terminated early due to certain mergers or other changes of control) or we have available cash but fail to make payments when due, generally we may elect to defer payments due under the Tax Receivable Agreement if we do not have available cash to satisfy our payment obligations under the Tax Receivable Agreement or if our contractual obligations limit our ability to make these payments. Any such deferred payments under the Tax Receivable Agreement generally will accrue interest. If we were to defer substantial payment obligations under the Tax Receivable Agreement on an ongoing basis, the accrual of those obligations would reduce the availability of cash for other purposes, but we would not be prohibited from paying dividends on our Class A common stock. See “Risk Factors—Risks Related to our Class A Common Stock” for risks related to the Tax Receivable Agreement.
Cash Flows
Year Ended
December 31, 2014
Compared to the
Year Ended
December 31, 2013
Our cash flows were as follows for the respective periods (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2014
|
|
2013
|
|
Change
|
Net cash provided by operating activities
|
$
|
5.9
|
|
|
$
|
44.5
|
|
|
$
|
(38.6
|
)
|
Net cash used in investing activities
|
$
|
(3.0
|
)
|
|
$
|
(1.5
|
)
|
|
$
|
(1.5
|
)
|
Net cash used in financing activities
|
$
|
(5.7
|
)
|
|
$
|
(42.4
|
)
|
|
$
|
36.7
|
|
Cash Flows Provided by Operating Activities
. Cash flows provided by operating activities for the year ended December 31, 2014 decreased by $38.6 million compared to the year ended December 31, 2013. The decrease was primarily due to increased customer acquisition cost spending primarily in California, Illinois and New York during the year ended December 31, 2014. In addition, the decrease in cash flows provided by operating activities was due to a decrease in retail gross margin due to the cost of supply in the first quarter of 2014 and an increase in general and administrative expenses, including bad debt expense, as discussed in “—Operating Segment Results”.
Cash Flows Used in Investing Activities
. Cash flows used in investing activities increased by $1.5 million for the year ended December 31, 2014 which was driven by a increase in capital expenditures related to the Company’s new customer billing and information system.
Cash Flows Used in Financing Activities
. Cash flows used in financing activities decreased by $36.7 million for the year ended December 31, 2014 due primarily to a $17.0 million increase in our borrowings, net of payments, under our credit facilities due to cash funding for operations and a $23.0 million decrease in net member distributions prior to the Offering, offset by a $3.3 million distribution and dividend paid in December 2014.
Year Ended
December 31, 2013 Compared to the
Year Ended
December 31, 2012
Our cash flows were as follows for the respective periods (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2013
|
|
2012
|
|
Change
|
|
|
|
|
|
|
Net cash provided by operating activities
|
$
|
44.5
|
|
|
$
|
44.1
|
|
|
$
|
0.4
|
|
Net cash used in investing activities
|
$
|
(1.5
|
)
|
|
$
|
(1.6
|
)
|
|
$
|
0.1
|
|
Net cash used in financing activities
|
$
|
(42.4
|
)
|
|
$
|
(39.9
|
)
|
|
$
|
(2.5
|
)
|
Cash Flows Provided by Operating Activities
. Net cash provided by operating activities was $44.1 million for the year ended December 31, 2012 and $44.5 million for the year ended December 31, 2013. Decreases in account receivable levels were generally offset by decreases in accounts payable, resulting in an immaterial impact on cash flow provided by operating activities. These decreases were primarily a result of lower retail sales volume offset by higher retail and wholesale prices. Net decreases in affiliate receivables increased operating cash flow by $21.1 million. Overall increases in commodity prices led to decreased operating cash flows, as both our inventory values and deposits required to transact in the wholesale market, which are recorded in other assets, increased with commodity prices.
Cash Flows Used in Investing Activities
. Net cash used in investing activities was $1.6 million for the year ended December 31, 2012 and $1.5 million for the year ended December 31, 2013. The $0.1 million decrease in cash used in investing activities was primarily attributable to decreased capital expenditures.
Cash Flows Used in Financing Activities
. Net cash used in financing activities was $39.9 million for the year ended December 31, 2012 and $42.4 million for the year ended December 31, 2013. The increase was primarily attributable to increased member distributions of $48.9 million partially offset by increased borrowings of $40.5 million on our working capital credit facility.
Credit Facility
Prior to the Offering, SE and SEG were co-borrowers under an $80 million revolving working capital credit facility with a maturity date of July 31, 2015. The total amounts outstanding under this facility prior to the Offering include distributions to the common control owner to fund unrelated operations of an affiliate.
In connection with the Offering, Spark HoldCo, SE and SEG (the “Co-Borrowers”) and Spark Energy, Inc., as guarantor, entered into a new $70.0 million senior secured revolving working capital credit facility (the “Senior Credit Facility”). The Senior Credit Facility has a maturity date of August 1, 2016. If no event of default has occurred, the Co-Borrowers have the right, subject to approval by the administrative agent and certain lenders, to increase the borrowing capacity under the new Senior Credit Facility to up to $120.0 million, which is available to fund expansions, acquisitions and working capital requirements for our operations and general corporate purposes, including distributions.
We borrowed approximately $10.0 million under the new Senior Credit Facility at the closing of the Offering to repay in full the outstanding indebtedness under our previous credit facility that SEG and SE had agreed to be responsible for pursuant to the interborrower agreement. The remainder of indebtedness outstanding under our previous credit facility was paid off by our affiliate with its own funds in connection with the closing of the Offering pursuant to the terms of the interborrower agreement. Following this repayment, our previous credit facility was terminated. We had $33.0 million outstanding on the Senior Credit Facility at December 31, 2014 and had approximately $10.7 million in letters of credit issued as of December 31, 2014.
At our election, interest under the Senior Credit Facility is generally determined by reference to:
|
|
•
|
the Eurodollar rate plus an applicable margin of up to 3.0% per annum (based upon the prevailing utilization);
|
|
|
•
|
the alternate base rate plus an applicable margin of up to 2.0% per annum (based upon the prevailing utilization). The alternate base rate is equal to the highest of (i) Société Générale’s prime rate, (ii) the federal funds rate plus 0.5% per annum, or (iii) the reference Eurodollar rate plus 1.0%; or
|
|
|
•
|
the rate quoted by Société Générale as its cost of funds for the requested credit plus 2.25% to 2.50% per annum.
|
The interest rate is generally reduced by 25 basis points if utilization under the Senior Credit Facility is below fifty percent. The Senior Credit Facility allows us to issue letters of credit, which reduce availability under Senior Credit Facility, at a cost of 2.00% to 2.50% per annum of aggregate letters of credit issued.
We pay an annual commitment fee of 0.375% or 0.5% on the unused portion of the Senior Credit Facility depending upon the unused capacity. The lending syndicate under the Senior Credit Facility is entitled to several additional fees including an upfront fee, annual agency fee, and fronting fees based on a percentage of the face amount of letters of credit payable to any syndicate member that issues a letter a credit.
The Senior Credit Facility is secured by the membership interests of SE, SEG and the equity of the Co-Borrowers’ present and future subsidiaries, all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.
The Senior Credit Facility contains covenants that, among other things, require the maintenance of specified ratios or conditions as follows:
Maximum Leverage Ratio
. Spark Energy, Inc. must maintain a consolidated maximum senior secured leverage ratio, consisting of total liabilities to tangible net worth of not more than 7.0 to 1.0, at any time.
Minimum Net Working Capital
. Spark Energy, Inc. must maintain minimum consolidated net working capital at all times equal to the greater of (i) 20% of the aggregate commitments under the Senior Credit Facility, and (ii) $12,000,000.
Minimum Tangible Net Worth.
Spark Energy, Inc. must maintain a minimum consolidated tangible net worth at all times equal to the net book value of property, plant and equipment as of the closing date of the Senior Credit Facility plus the greater of (i) 20% of aggregate commitments under the Senior Credit Facility and (ii) $12,000,000.
The borrowing base, which is recalculated and reported monthly, is calculated primarily based on 80 to 90% of the value of eligible accounts receivable and unbilled product sales (depending on the credit quality of the counterparties) and inventory and other working capital assets. The Co-borrowers under the Senior Credit Facility must prepay any amounts outstanding under the Senior Credit Facility in excess of the borrowing base (up to the maximum availability amount).
In addition, the Senior Credit Facility contains customary affirmative covenants. The covenants include delivery of financial statements and other information (including any filings made with the SEC), maintenance of property and insurance, maintenance of holding company status at Spark Energy, Inc., payment of taxes and obligations, material
compliance with laws, inspection of property, books and records and audits, use of proceeds, payments to bank blocked accounts, notice of defaults and certain other customary matters. The Senior Credit Facility also contains additional negative covenants that limits our ability to, among other things, do any of the following:
|
|
•
|
incur certain additional indebtedness,
|
|
|
•
|
engage in certain asset dispositions,
|
|
|
•
|
make certain payments, distributions (as noted below), investments, acquisitions or loans,
|
|
|
•
|
enter into transactions with affiliates,
|
|
|
•
|
make certain changes in our lines of business or accounting practices, except as required by GAAP or its successor,
|
|
|
•
|
store inventory in certain locations,
|
|
|
•
|
place certain amounts of cash in accounts not subject to control agreements,
|
|
|
•
|
amend or modify billing services agreements and documents,
|
|
|
•
|
engage in certain prohibited transactions,
|
|
|
•
|
enter into burdensome agreements, and
|
|
|
•
|
act as a transmitting utility or as a utility.
|
Certain of the negative covenants listed above are subject to certain permitted exceptions and allowances.
Spark Energy, Inc. is entitled to pay cash dividends to the holders of the Class A common stock and Spark HoldCo is entitled to make cash distributions to NuDevco and us so long as: (a) no default exists or would result from such a payment; (b) the Co-Borrowers are in pro forma compliance with all financial covenants (as defined above) before and after giving effect to such payment and (c) the outstanding amount of all loans and letters of credit does not exceed the borrowing base limits. Spark HoldCo’s inability to satisfy certain financial covenants or the existence of an event of default, if not cured or waived, under the Senior Credit Facility could prevent us from paying dividends to holders of our Class A common stock.
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 $2.5 million, certain events with respect to material contracts, actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect and changes of control. If such an event of default occurs, the lenders under the Senior Credit Facility are 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.
Summary of Contractual Obligations
The following table discloses aggregate information about our contractual obligations and commercial commitments as of December 31, 2014 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
2015
|
2016
|
2017
|
2018
|
2019
|
> 5 years
|
Operating leases (1)
|
$
|
1.1
|
|
$
|
1.1
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Purchase obligations:
|
|
|
|
|
|
|
|
Natural gas and electricity related purchase obligations (2)
|
8.4
|
|
4.7
|
|
3.7
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Pipeline transportation agreements
|
18.1
|
|
5.5
|
|
3.1
|
|
2.6
|
|
1.0
|
|
0.8
|
|
5.1
|
|
Other purchase obligations (3)
|
9.4
|
|
3.9
|
|
3.8
|
|
1.7
|
|
—
|
|
—
|
|
—
|
|
Total purchase obligations
|
$
|
37.0
|
|
$
|
15.2
|
|
$
|
10.6
|
|
$
|
4.3
|
|
$
|
1.0
|
|
$
|
0.8
|
|
$
|
5.1
|
|
Debt
|
$
|
33.0
|
|
$
|
33.0
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
(1) Included in the total amount are future minimum payments for office and other operating leases.
(2) The amounts represent the notional value of natural gas and electricity related purchase contracts that are not accounted for as derivative financial instruments recorded at fair market value as the company has elected the normal purchase normal sale exception, and therefore are not recognized as liabilities on the combined and consolidated balance sheet.
(3) The amounts presented here include contracts for billing services and other software agreements.
Off-Balance Sheet Arrangements
As of December 31, 2014 we had no material off-balance sheet arrangements.
Related Party Transactions
For a discussion of related party transactions see Note 11 “Transactions with Affiliates” in the Company’s audited combined and consolidated financial statements.
Critical Accounting Policies and Estimates
Our significant accounting policies are described in Note 2 to our audited combined and consolidated financial statements. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America and pursuant to the rules and regulations of the SEC, which require us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying footnotes. Actual results could differ from those estimates. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our financial condition and results of operations.
Revenue Recognition
Our revenues are derived primarily from the sale of natural gas and electricity to retail customers. We also record revenues from sales of natural gas and electricity to wholesale counterparties, including affiliates. Revenues are recognized by using the following criteria: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the buyer’s price is fixed or determinable and (4) collection is reasonably assured. Utilizing these criteria, revenue is recognized when the natural gas or electricity is delivered. Similarly, cost of revenues is recognized when the commodity is delivered.
Revenues for natural gas and electricity sales are recognized upon delivery under the accrual method. Natural gas and electricity sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read provided by the utility. Volume
estimates are based on forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
The cost of natural gas and electricity for sale to retail customers is based on estimated supply volumes for the applicable reporting period. In estimating supply volumes, we consider the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees, where applicable, are estimated using the same method used for sales to retail customers. In addition, other load related costs, such as ISO fees, ancillary services and renewable energy credits are estimated based on historical trends, estimated supply volumes and initial utility data. Volume estimates are then multiplied by the supply rate and recorded as retail cost of revenues in the applicable reporting period. Estimated amounts are adjusted when actual usage is known and billed.
Our asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage and transportation opportunities, meet the definition of trading activities and are recorded on a net basis in the combined and consolidated statements of operations in net asset optimization revenues as required by the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815,
Derivatives and Hedging.
Accounts Receivable
We accrue an allowance for doubtful accounts based upon estimated uncollectible accounts receivable considering historical collections, accounts receivable aging analysis, credit risk and other factors. We write off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is deemed to be uncollectible.
We conduct business in many utility service markets where the local regulated utility is responsible for billing the customer, collecting payment from the customer and remitting payment to the Company (“POR programs”). This POR service results in substantially all of our credit risk being linked to the applicable utility in these territories, which generally has an investment-grade rating, and not to the end-use customer. We monitor the financial condition of each utility and currently believe that our susceptibility to an individually significant write-off as a result of concentrations of customer accounts receivable with those utilities is remote.
In markets that do not offer POR services or when we choose to directly bill our customers, certain accounts receivable are billed and collected by us. We bear the credit risk on these accounts and record an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. Our customers are individually insignificant and geographically dispersed in these markets. We write off customer balances when we believe that amounts are no longer collectible and when we have exhausted all means to collect these receivables.
Capitalized Customer Acquisition Costs
Capitalized customer acquisition costs consist primarily of hourly and commission based telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven customer generation, and are capitalized and amortized over the estimated two-year average life of a customer in accordance with the provisions of FASB ASC 340-20,
Capitalized Advertising Costs
.
Recoverability of customer acquisition costs is evaluated based on a comparison of the carrying amount of the customer acquisition costs to the future net cash flows expected to be generated by the customers acquired, considering specific assumptions for customer attrition, per unit gross profit, and operating costs. These assumptions are based on forecasts and historical experience.
Accounting for Derivative and Hedging Activities
We use derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of our business operations.
All derivatives, other than those for which an exception applies, are recorded in the combined and consolidated balance sheets at fair value. Derivative instruments representing unrealized gains are reported as derivative assets while derivative instruments representing unrealized losses are reported as derivative liabilities. We have elected to offset amounts on the combined and consolidated balance sheets for recognized derivative instruments executed with the same counterparty under a master netting arrangement. One of the exceptions to fair value accounting, normal purchases and normal sales, has been elected by us for certain derivative instruments when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable and is expected to be used in normal course of business. Retail revenues and retail cost of revenues resulting from deliveries of commodities under normal purchase contracts and normal sales contracts are included in earnings at the time of contract settlement.
To manage commodity price risk, we hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent we do not hold offsetting positions for such derivatives, we believe these instruments represent economic hedges that mitigate our exposure to fluctuations in commodity prices. As part of our strategy to optimize our assets and manage related commodity risks, we also manage a portfolio of commodity derivative instruments held for trading purposes. We use established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and use derivative instruments to reduce risk by generally creating offsetting market positions.
Changes in the fair value of and amounts realized upon settlement of derivative instruments not held for trading purposes are recognized currently in earnings in retail revenues or retail costs of revenues, respectively.
Changes in the fair value of and amounts realized upon settlement of derivative instruments held for trading purposes are recognized currently in earnings in net asset optimization revenues.
We have historically designated a portion of our derivative instruments as cash flow hedges for accounting purposes. For all hedging transactions, we formally documented the hedging transaction and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk was assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. We also formally assessed, both at the inception of the hedging transaction and on an ongoing basis, whether the derivatives used in hedging transactions were highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that were designated and qualified as part of a cash flow hedging transaction, the effective portion of the gain or loss on the derivative was reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during when the hedged transaction affected earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness were recognized in current earnings. Hedge accounting was discontinued prospectively for derivatives that ceased to be highly effective hedges or when the occurrence of the forecasted transaction was no longer probable.
Effective July 1, 2013, we elected to discontinue hedge accounting prospectively and began to record the changes in fair value recognized in the combined and consolidated statement of operations in the period of change. Because the underlying transactions were still probable of occurring, the related accumulated other comprehensive income was frozen and recognized in earnings as the underlying hedged item was delivered. As of December 31, 2014 and 2013, we had no gains or losses on derivatives that were designated as qualifying cash flow hedging transactions recorded as a component of accumulated other comprehensive income, as all previously deferred gains and losses on qualifying hedge transactions were reclassified into earnings during the year ended December 31, 2013 when the associated hedged transactions were recorded into earnings.
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09,
Revenue from Contracts with Customers
, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.
In August 2014, the FASB issued ASU No. 2014-15, P
resentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern
(“ASU 2014-15”). The new guidance clarifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosure. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. The Company does not expect the adoption to have a material effect on the combined or consolidated financial statements.
In November 2014, the FASB issued ASU No. 2014-16,
Derivatives and Hedging
, which clarifies how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The amendments in this Update are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Update does not change the current criteria in GAAP for determining when separation of certain embedded derivative features in a hybrid financial instrument is required. The Company does not believe the adoption of this ASU to have a material impact on the combined and consolidated financial statements.
In February 2015, the FASB issued ASU No. 2015-02,
Consolidation
(Topic 810)
(“ASU 2015-02”). The new guidance changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption at an interim period. The Company has not yet determined the effect of the standard on its ongoing financial reporting.
Contingencies
In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including regulatory and other matters. As of
December 31, 2014
, management does not believe that any of our outstanding lawsuits, administrative proceedings or investigations could result in a material adverse effect.
Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Emerging Growth Company Status
We are an “emerging growth company” within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with certain requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of
the Securities Act for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.
We intend to take advantage of these exemptions until we are no longer an emerging growth company. We will cease to be an “emerging growth company” upon the earliest of: (i) the last day of the fiscal year in which we have $1.0 billion or more in annual revenues; (ii) the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or (iv) the last day of the fiscal year following the fifth anniversary of the Offering.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risks relating to our operations result primarily from changes in commodity prices and interest rates, as well as counterparty credit risk. We employ established policies and procedures to manage our exposure to these risks.
Commodity Price Risk
We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets and through short and long term contracts. Our financial results are largely dependent on the margin we are able to realize between the wholesale purchase price of natural gas and electricity plus related costs and the retail sales price we charge our customers. We actively manage our commodity price risk by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from fixed-price forecasted sales and purchases of natural gas and electricity in connection with our retail energy operations. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. These contracts have varying terms and durations, which range from a few days to a few years, depending on the instrument. Our asset optimization group utilizes similar derivative contracts in connection with its trading activities to attempt to generate incremental gross margin by effecting transactions in markets where we have a retail presence. Generally, any of such instruments that are entered into to support our retail electricity and natural gas business are categorized as having been entered into for non-trading purposes, and instruments entered into for any other purpose are categorized as having been entered into for trading purposes. Our net loss on non-trading derivative instruments net of cash settlements was $15.0 million for the year ended December 31, 2014. This non-cash loss was due to a decline in wholesale gas and electricity market prices against our fixed price hedge portfolio. As this future supply has been sold to customers at fixed prices, changes in the value of the hedge portfolio should have no impact on future margin. Additionally, the decline in market prices led to a cash collateral posting to our FCM, Futures Commission Merchant, of $7.4 million as of December 31, 2014 compared to $2.0 million as of December 31, 2013.
We have adopted risk management policies to measure and limit market risk associated with our fixed-price portfolio and our hedging activities. For additional information regarding our commodity price risk and our risk management policies, see “Item 1A - Risk Factors
”
.
We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of December 31, 2014, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a long position of 429,395 MMBtu, due primarily to our retail choice storage being close to full as we approach winter. An increase in 10% in the market prices (NYMEX) from their December 31, 2014 levels would have increased the fair market value of our net non-trading energy portfolio by $0.4 million. Likewise, a decrease in 10% in the market prices (NYMEX) from their December 31, 2014 levels would have decreased the fair market value of our non-trading energy derivatives by $0.4 million. As of December 31, 2014, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 53,509 MWhs. An increase in 10% in the forward market prices from their December 31, 2014 levels would have decreased the fair market value of our net non-trading energy portfolio by $0.4 million. Likewise, a decrease in 10% in the forward market prices from their December 31, 2014 levels would have increased the fair market value of our non-trading energy derivatives by $0.4 million.
We measure the commodity risk of our trading energy derivatives using a sensitivity analysis on our net open position. As of December 31, 2014, our Gas Trading Fixed Price Open Position was a long position of 17,715 MMBtu. An increase in 10% in the market prices (NYMEX) from their December 31, 2014 levels would have increased the fair market value of our trading energy derivatives by less than $0.1 million. Likewise, a decrease in 10% in the market prices (NYMEX) from their December 31, 2014 levels would have decreased the fair market value of our trading energy derivatives by less than $0.1 million.
Credit Risk
In many of the utility services territories where we conduct business, POR programs have been established, whereby the local regulated utility offers services for billing the customer, collecting payment from the customer and remitting payment to us. This service results in substantially all of our credit risk being linked to the applicable utility and not to our end-use customer in these territories. Approximately 44%, 47% and 55% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies as of December 31, 2014, 2013 and 2012, respectively, all of which had investment grade ratings as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately 1.0% of total revenues for customer credit risk. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods.
In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit screening, deposits, disconnection for non-payment and collection efforts in the case of residential customers. Our bad debt expense for the year ended December 31, 2014, 2013 and 2012 was approximately 5.7%, 1.8% and 1.1% of non-POR market retail revenues, respectively. Economic conditions may affect our customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. See
“
Management's Discussion and Analysis of Financial Condition and Results of Operations—Drivers of our Business—Customer Credit Risk” for an analysis of our bad debt expense related to non-POR markets during 2014.
We are exposed to wholesale counterparty credit risk in our retail and asset optimization activities. We manage this risk at a counterparty level and secure our exposure with collateral or guarantees when needed. At December 31, 2014 and 2013, approximately 50% and 82% of our total exposure of $8.8 million and $12.5 million, respectively, was either with an investment grade customer or otherwise secured with collateral. The credit worthiness of the remaining exposure with other customers was evaluated with no material allowance recorded at December 31, 2014, 2013 and 2012.
Interest Rate Risk
We are exposed to fluctuations in interest rates under our variable-price debt obligations. At December 31, 2014 we have a $70 million variable rate Senior Credit Facility under which $33.0 million of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the year ended December 31, 2014, a 1% percent increase in interest rates would have resulted in additional annual interest expense of approximately $0.3 million. We do not currently employ interest rate hedges, although we may choose to do so in the future.
Item 8. Financial Statements and Supplementary Data
|
|
|
|
ITEM 8. FINANCIAL STATEMENTS
|
|
|
|
|
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
|
|
|
|
|
|
COMBINED AND CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2014 AND DECEMBER 31, 2013
|
|
|
|
|
|
COMBINED AND CONSOLIDATED STATEMENT OF OPERATIONS AND COMPREHENSIVE (LOSS) INCOME FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012
|
|
|
|
|
|
COMBINED AND CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012
|
|
|
|
|
|
COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012
|
|
|
|
|
|
NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Spark Energy, Inc.:
We have audited the accompanying combined and consolidated balance sheets of Spark Energy, Inc. as of December 31, 2014 and 2013, and the related combined and consolidated statements of operations and comprehensive (loss) income, changes in equity, and cash flows for each of the years in the three‑year period ended December 31, 2014. These combined and consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined and consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined and consolidated financial statements referred to above present fairly, in all material respects, the financial position of Spark Energy, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Houston, Texas
March 27, 2015
AUDITED COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
SPARK ENERGY, INC.
COMBINED AND CONSOLIDATED BALANCE SHEETS
AS OF
DECEMBER 31, 2014
AND
DECEMBER 31, 2013
(in thousands)
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
December 31, 2013
|
Assets
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
4,359
|
|
|
$
|
7,189
|
|
Restricted cash
|
707
|
|
|
—
|
|
Accounts receivable, net of allowance for doubtful accounts of $8.0 million and $1.2 million as of December 31, 2014 and 2013, respectively
|
63,797
|
|
|
62,678
|
|
Accounts receivable-affiliates
|
1,231
|
|
|
6,794
|
|
Inventory
|
8,032
|
|
|
4,322
|
|
Fair value of derivative assets
|
216
|
|
|
8,071
|
|
Customer acquisition costs, net
|
12,369
|
|
|
4,775
|
|
Intangible assets - customer acquisitions, net
|
486
|
|
|
—
|
|
Prepaid assets
|
1,236
|
|
|
1,032
|
|
Deposits
|
10,569
|
|
|
3,529
|
|
Other current assets
|
2,987
|
|
|
2,901
|
|
Total current assets
|
105,989
|
|
|
101,291
|
|
Property and equipment, net
|
4,221
|
|
|
4,817
|
|
Fair value of derivative assets
|
—
|
|
|
6
|
|
Customer acquisition costs
|
2,976
|
|
|
2,901
|
|
Intangible assets - customer acquisitions
|
1,015
|
|
|
—
|
|
Deferred tax assets
|
24,047
|
|
|
—
|
|
Other assets
|
149
|
|
|
58
|
|
Total Assets
|
$
|
138,397
|
|
|
$
|
109,073
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable
|
$
|
38,210
|
|
|
$
|
36,971
|
|
Accounts payable-affiliates
|
1,017
|
|
|
—
|
|
Accrued liabilities
|
7,195
|
|
|
6,838
|
|
Fair value of derivative liabilities
|
11,526
|
|
|
1,833
|
|
Note payable
|
33,000
|
|
|
27,500
|
|
Other current liabilities
|
1,868
|
|
|
—
|
|
Total current liabilities
|
92,816
|
|
|
73,142
|
|
Long-term liabilities:
|
|
|
|
|
|
Fair value of derivative liabilities
|
478
|
|
|
18
|
|
Payable pursuant to tax receivable agreement-affiliates
|
20,767
|
|
|
—
|
|
Other long-term liabilities
|
219
|
|
|
—
|
|
Total liabilities
|
114,280
|
|
|
73,160
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
Stockholders' equity:
|
|
|
|
|
|
Member's equity
|
—
|
|
|
35,913
|
|
Common Stock:
|
|
|
|
|
|
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 3,000,000 issued and outstanding at December 31, 2014 and zero authorized, issued and outstanding at December 31, 2013
|
30
|
|
|
—
|
|
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 10,750,000 issued and outstanding at December 31, 2014 and zero authorized, issued and outstanding at December 31, 2013
|
108
|
|
|
—
|
|
Preferred Stock:
|
|
|
|
|
|
Preferred stock, par value $0.01 per share, 20,000,000 shares authorized, zero issued and outstanding at December 31, 2014 and zero authorized, issued and outstanding at December 31, 2013
|
—
|
|
|
—
|
|
Additional paid-in capital
|
9,296
|
|
|
—
|
|
Retained deficit
|
(775
|
)
|
|
—
|
|
Total stockholders' equity
|
8,659
|
|
|
35,913
|
|
Non-controlling interest in Spark HoldCo, LLC
|
15,458
|
|
|
—
|
|
Total equity
|
24,117
|
|
|
35,913
|
|
Total Liabilities and Stockholders' Equity
|
$
|
138,397
|
|
|
$
|
109,073
|
|
The accompanying notes are an integral part of the combined and consolidated financial statements.
SPARK ENERGY, INC.
COMBINED AND CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE (LOSS) INCOME
FOR THE
YEARS ENDED
DECEMBER 31, 2014
,
2013
and
2012
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
|
2012
|
Revenues:
|
|
|
|
|
|
Retail revenues (including retail revenues—affiliates of $2,170, $4,022 and $1,382 for the years ended December 31, 2014, 2013 and 2012, respectively)
|
$
|
320,558
|
|
|
$
|
316,776
|
|
|
$
|
380,198
|
|
Net asset optimization revenues (expenses) (including asset optimization revenues-affiliates of $12,842, $14,940 and $8,334 for the years ended December 31, 2014, 2013 and 2012, respectively, and asset optimization revenues affiliates cost of revenues of $30,910, $15,928 and $568 for the years ended December 31, 2014, 2013 and 2012, respectively)
|
2,318
|
|
|
314
|
|
|
(1,136
|
)
|
Total Revenues
|
322,876
|
|
|
317,090
|
|
|
379,062
|
|
Operating Expenses:
|
|
|
|
|
|
Retail cost of revenues (including retail cost of revenues-affiliates of $13, $55 and $254 for the years December 31, 2014, 2013 and 2012, respectively)
|
258,616
|
|
|
233,026
|
|
|
279,506
|
|
General and administrative (including general and administrative expense-affiliates of less than $100, less than $100 and $800 for the years ended December 31, 2014, 2013 and 2012, respectively)
|
45,880
|
|
|
35,020
|
|
|
47,321
|
|
Depreciation and amortization
|
22,221
|
|
|
16,215
|
|
|
22,795
|
|
Total Operating Expenses
|
326,717
|
|
|
284,261
|
|
|
349,622
|
|
Operating (loss) income
|
(3,841
|
)
|
|
32,829
|
|
|
29,440
|
|
Other (expense)/income:
|
|
|
|
|
|
Interest expense
|
(1,578
|
)
|
|
(1,714
|
)
|
|
(3,363
|
)
|
Interest and other income
|
263
|
|
|
353
|
|
|
62
|
|
Total other expenses
|
(1,315
|
)
|
|
(1,361
|
)
|
|
(3,301
|
)
|
(Loss) income before income tax expense
|
(5,156
|
)
|
|
31,468
|
|
|
26,139
|
|
Income tax (benefit) expense
|
(891
|
)
|
|
56
|
|
|
46
|
|
Net (loss) income
|
(4,265
|
)
|
|
31,412
|
|
|
26,093
|
|
Less: Net (loss) attributable to non-controlling interests
|
(4,211
|
)
|
|
—
|
|
|
—
|
|
Net (loss) income attributable to Spark Energy, Inc. stockholders
|
$
|
(54
|
)
|
|
$
|
31,412
|
|
|
$
|
26,093
|
|
Other comprehensive (loss) income:
|
|
|
|
|
|
Deferred gain (loss) from cash flow hedges
|
—
|
|
|
2,620
|
|
|
(10,243
|
)
|
Reclassification of deferred gain (loss) from cash flow hedges into net income (Note 6)
|
—
|
|
|
(84
|
)
|
|
17,942
|
|
Comprehensive (loss) income
|
$
|
(4,265
|
)
|
|
$
|
33,948
|
|
|
$
|
33,792
|
|
|
|
|
|
|
|
Net loss attributable to Spark Energy, Inc. per common share
|
|
|
|
|
|
Basic
|
$
|
(0.02
|
)
|
|
|
|
|
|
Diluted
|
$
|
(0.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average commons shares outstanding
|
|
|
|
|
|
|
|
Basic
|
3,000
|
|
|
|
|
|
|
Diluted
|
3,000
|
|
|
|
|
|
|
The accompanying notes are an integral part of the combined and consolidated financial statements.
SPARK ENERGY, INC.
COMBINED AND CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE
YEARS ENDED
DECEMBER 31, 2014
, 2013 and 2012
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Member's Equity
|
Issued Shares of Class A Common Stock
|
Issued Shares of Class B Common Stock
|
Issued Shares of Preferred Stock
|
Class A Common Stock
|
Class B Common Stock
|
Accumulated Other Comprehensive Income
|
Additional Paid In Capital
|
Retained Deficit
|
Total Stockholders Equity
|
Non-controlling Interest
|
Total Equity
|
Balance at 12/31/2011:
|
$
|
48,180
|
|
—
|
|
—
|
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(10,235
|
)
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
37,945
|
|
Capital contributions from member
|
10,060
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
10,060
|
|
Distributions to member
|
(20,495
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(20,495
|
)
|
Net income
|
26,093
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
26,093
|
|
Deferred loss from cash flow hedges
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(10,243
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(10,243
|
)
|
Reclassification of deferred gain from cash flow hedges into net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
17,942
|
|
—
|
|
—
|
|
—
|
|
—
|
|
17,942
|
|
Balance at 12/31/2012:
|
63,838
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,536
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
61,302
|
|
Capital contributions from member
|
12,400
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
12,400
|
|
Distributions to member
|
(71,737
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(71,737
|
)
|
Net income
|
31,412
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
31,412
|
|
Deferred gain from cash flow hedges
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,620
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,620
|
|
Reclassification of deferred loss from cash flow hedges into net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(84
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(84
|
)
|
Balance at 12/31/2013:
|
35,913
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
35,913
|
|
Capital contributions from member and liabilities retained by affiliate
|
54,201
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
54,201
|
|
Distributions to member
|
(61,607
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(61,607
|
)
|
Net loss prior to the Offering
|
(21
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(21
|
)
|
Balance prior to Corporate Reorganization and the Offering:
|
28,486
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
28,486
|
|
Reorganization Transaction:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of Class B common stock
|
(28,486
|
)
|
—
|
|
10,750
|
|
—
|
|
—
|
|
108
|
|
—
|
|
28,378
|
|
—
|
|
28,486
|
|
—
|
|
—
|
|
Offering Transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Offering costs paid
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,667
|
)
|
—
|
|
(2,667
|
)
|
—
|
|
(2,667
|
)
|
Issuance of Class A Common Stock, net of underwriters discount
|
—
|
|
3,000
|
|
—
|
|
—
|
|
30
|
|
—
|
|
—
|
|
50,190
|
|
—
|
|
50,220
|
|
—
|
|
50,220
|
|
Distribution of Offering proceeds and payment of note payable to affiliate
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(47,604
|
)
|
—
|
|
(47,604
|
)
|
—
|
|
(47,604
|
)
|
Initial allocation of non-controlling interest of Spark Energy, Inc. effective on date of Offering
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(22,232
|
)
|
—
|
|
(22,232
|
)
|
22,232
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax benefit from tax receivable agreement
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
23,636
|
|
—
|
|
23,636
|
|
—
|
|
23,636
|
|
Liability due to tax receivable agreement
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(20,915
|
)
|
—
|
|
(20,915
|
)
|
—
|
|
(20,915
|
)
|
Balance at inception of public company (8/1/2014):
|
—
|
|
3,000
|
|
10,750
|
|
—
|
|
30
|
|
108
|
|
—
|
|
8,786
|
|
—
|
|
8,924
|
|
22,232
|
|
31,156
|
|
Stock based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
510
|
|
—
|
|
510
|
|
—
|
|
510
|
|
Consolidated net loss subsequent to the Offering
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(54
|
)
|
(54
|
)
|
(4,190
|
)
|
(4,244
|
)
|
Distributions paid to Class B non-controlling unit holders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,584
|
)
|
(2,584
|
)
|
Dividends paid to Class A common shareholders
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(721
|
)
|
(721
|
)
|
—
|
|
(721
|
)
|
Balance at 12/31/2014:
|
$
|
—
|
|
3,000
|
|
10,750
|
|
—
|
|
$
|
30
|
|
$
|
108
|
|
$
|
—
|
|
$
|
9,296
|
|
$
|
(775
|
)
|
$
|
8,659
|
|
$
|
15,458
|
|
$
|
24,117
|
|
The accompanying notes are an integral part of the combined and consolidated financial statements.
SPARK ENERGY, INC.
COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE
YEARS ENDED
DECEMBER 31, 2014
,
2013
AND 2012
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
|
2012
|
Cash flows from operating activities:
|
|
|
|
|
|
Net (loss) income
|
$
|
(4,265
|
)
|
|
$
|
31,412
|
|
|
$
|
26,093
|
|
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
|
|
|
|
|
|
Depreciation and amortization expense
|
22,221
|
|
|
16,215
|
|
|
22,795
|
|
Deferred income taxes
|
(1,064
|
)
|
|
—
|
|
|
—
|
|
Stock based compensation
|
858
|
|
|
—
|
|
|
—
|
|
Amortization and write off of deferred financing costs
|
631
|
|
|
678
|
|
|
919
|
|
Bad debt expense
|
10,164
|
|
|
3,101
|
|
|
1,835
|
|
(Gain) loss on derivatives, net
|
14,535
|
|
|
(6,567
|
)
|
|
21,485
|
|
Current period cash settlements on derivatives, net
|
3,479
|
|
|
(1,040
|
)
|
|
(26,801
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
Increase in restricted cash
|
(707
|
)
|
|
—
|
|
|
—
|
|
(Increase) decrease in accounts receivable
|
(11,283
|
)
|
|
6,338
|
|
|
12,019
|
|
(Increase) decrease in accounts receivable-affiliates
|
5,563
|
|
|
13,369
|
|
|
(7,787
|
)
|
(Increase) decrease in inventory
|
(3,711
|
)
|
|
(599
|
)
|
|
3,442
|
|
Increase in customer acquisition costs
|
(26,191
|
)
|
|
(8,257
|
)
|
|
(6,322
|
)
|
(Increase) decrease in prepaid and other current assets
|
(6,905
|
)
|
|
(1,917
|
)
|
|
8,505
|
|
(Increase) decrease in other assets
|
(90
|
)
|
|
144
|
|
|
345
|
|
Increase in intangible assets - customer acquisitions
|
(1,545
|
)
|
|
—
|
|
|
—
|
|
Increase (decrease) in accounts payable and accrued liabilities
|
1,449
|
|
|
(7,879
|
)
|
|
(11,394
|
)
|
Increase (decrease) in accounts payable-affiliates
|
1,017
|
|
|
—
|
|
|
(1,295
|
)
|
Increase (decrease) in other current liabilities
|
1,867
|
|
|
(518
|
)
|
|
237
|
|
Decrease in other non-current liabilities
|
(149
|
)
|
|
—
|
|
|
—
|
|
Net cash provided by operating activities
|
5,874
|
|
|
44,480
|
|
|
44,076
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Purchases of property and equipment
|
(3,040
|
)
|
|
(1,481
|
)
|
|
(2,220
|
)
|
Sale of property, plant and equipment-affiliates
|
—
|
|
|
—
|
|
|
577
|
|
Net cash used in investing activities
|
(3,040
|
)
|
|
(1,481
|
)
|
|
(1,643
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
Borrowings on notes payable
|
78,500
|
|
|
80,000
|
|
|
39,500
|
|
Payments on notes payable
|
(44,000
|
)
|
|
(62,500
|
)
|
|
(68,528
|
)
|
Deferred financing costs
|
(402
|
)
|
|
(532
|
)
|
|
(441
|
)
|
Member contribution (distributions), net
|
(36,406
|
)
|
|
(59,337
|
)
|
|
(10,435
|
)
|
Proceeds from issuance of Class A common stock
|
50,220
|
|
|
—
|
|
|
—
|
|
Distributions of proceeds from Offering to affiliate
|
(47,554
|
)
|
|
—
|
|
|
—
|
|
Payment of note payable to NuDevco
|
(50
|
)
|
|
—
|
|
|
—
|
|
Offering costs
|
(2,667
|
)
|
|
—
|
|
|
—
|
|
Payment of distributions to Class B non-controlling unit holders
|
(2,584
|
)
|
|
—
|
|
|
—
|
|
Payment of dividends to Class A common shareholders
|
(721
|
)
|
|
—
|
|
|
—
|
|
Net cash used in financing activities
|
(5,664
|
)
|
|
(42,369
|
)
|
|
(39,904
|
)
|
Decreases in cash and cash equivalents
|
(2,830
|
)
|
|
630
|
|
|
2,529
|
|
Cash and cash equivalents—beginning of period
|
7,189
|
|
|
6,559
|
|
|
4,030
|
|
Cash and cash equivalents—end of period
|
$
|
4,359
|
|
|
$
|
7,189
|
|
|
$
|
6,559
|
|
Supplemental Disclosure of Cash Flow Information:
|
|
|
|
|
|
Non cash items:
|
|
|
|
|
|
Issuance of Class B common stock
|
$
|
28,486
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Liabilities retained by affiliate
|
$
|
29,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Tax benefit from tax receivable agreement
|
$
|
23,636
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Liability due to tax receivable agreement
|
$
|
20,767
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Initial allocation of non-controlling interest
|
$
|
22,232
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Property and equipment purchase accrual
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Cash paid during the period for:
|
|
|
|
|
|
Interest
|
$
|
860
|
|
|
$
|
879
|
|
|
$
|
2,686
|
|
Taxes
|
$
|
85
|
|
|
$
|
195
|
|
|
$
|
318
|
|
The accompanying notes are an integral part of the combined and consolidated financial statements.
SPARK ENERGY, INC.
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Organization
Organization
Spark Energy, Inc. (the “Company”) is an independent retail energy services company that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. The Company is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). Spark HoldCo owns all of the outstanding membership interests in each of Spark Energy, LLC (“SE”) and Spark Energy Gas, LLC (“SEG”), the operating subsidiaries through which the Company operates. The Company is the sole managing member of Spark HoldCo, is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries.
The Company is a Delaware corporation formed on April 22, 2014 by Spark Energy Ventures, LLC (“Spark Energy Ventures”) for the purpose of succeeding to Spark Energy Ventures’ ownership in SE and SEG. Spark Energy Ventures, a single member limited liability company formed on October 8, 2007 under the Texas Limited Liability Company Act (“TLLCA”) is an affiliate of NuDevco Retail Holdings, LLC (“NuDevco Retail Holdings”), a single member Texas limited liability company formed by Spark Energy Ventures on May 19, 2014 under the Texas Business Organizations Code (“TBOC”). NuDevco Retail Holdings was formed by Spark Energy Ventures to hold its investment in Spark HoldCo, LLC, our subsidiary and the direct parent of SEG and SE. NuDevco Retail Holdings is currently a direct wholly owned subsidiary of Spark Energy Ventures, which is wholly owned by NuDevco Partners Holdings, LLC, which is wholly owned by NuDevco Partners, LLC (“NuDevco Partners”), which is wholly owned by W. Keith Maxwell III. NuDevco Retail Holdings formed NuDevco Retail, LLC (“NuDevco Retail” and, together with NuDevco Retail Holdings, “NuDevco”), a single member limited liability company, on May 29, 2014 and it holds a
1%
interest in Spark HoldCo formerly held by NuDevco Retail Holdings.
Prior to the closing of the Company’s initial public offering of
3,000,000
shares of Class A common stock, par value
$0.01
per share (the “Class A common stock”), representing a
21.82%
interest in the Company, on August 1, 2014 (the “Offering”), Spark Energy Ventures contributed all of its interest in each of SE and SEG to NuDevco Retail Holdings. NuDevco Retail Holdings in turn contributed all of its interest in each of SE and SEG to Spark HoldCo. The contribution of the interests in SE and SEG to Spark HoldCo is not considered a business combination accounted for under the purchase method, as it was a transfer of assets and operations under common control, and accordingly, balances were transferred at their historical cost. The Company’s historical combined financial statements prior to the Offering are prepared using SE’s and SEG’s historical basis in the assets and liabilities, and include all revenues, costs, assets and liabilities attributed to the retail natural gas and asset optimization and retail electricity businesses of SE and SEG.
SE is a licensed retail electric provider in multiple states. SE provides retail electricity services to end-use retail customers, ranging from residential and small commercial customers to large commercial and industrial users. SE was formed on February 5, 2002 under the Texas Revised Limited Partnership Act (as recodified by the TBOC) and was converted to a Texas limited liability company on May 21, 2014.
SEG is a retail natural gas provider and asset optimization business competitively serving residential, commercial and industrial customers in multiple states. SEG was formed on January 17, 2001 under the Texas Revised Limited Partnership Act (as recodified by the TBOC) and was converted to a Texas limited liability company on May 21, 2014.
As a company with less than $1.0 billion in revenues during its last fiscal year, the Company qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements.
The Company will remain an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the fiscal year in which the Company has $1.0 billion or more in annual revenues; (ii) the date on which the Company becomes a “large accelerated filer” (the fiscal year-end on which the total market value of the Company’s common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which the Company issues more than $1.0 billion of non-convertible debt over a three-year period; or (iv) the last day of the fiscal year following the fifth anniversary of the Offering.
As a result of the Company's election to avail itself of certain provisions of the JOBS Act, the information that the Company provides may be different than what you may receive from other public companies in which you hold an equity interest.
Initial Public Offering of Spark Energy, Inc.
On August 1, 2014, the Company completed the Offering of
3,000,000
shares of its Class A common stock for
$18.00
per share, representing a
21.82%
voting interest in the Company.
Net proceeds from the Offering were
$47.6 million
, after underwriting discounts and commissions, structuring fees and offering expenses. The net proceeds from the Offering were used to acquire units of Spark HoldCo (the “Spark HoldCo units”) representing approximately
21.82%
of the outstanding Spark HoldCo units after the Offering from NuDevco Retail Holdings and to repay a promissory note from the Company in the principal amount of
$50,000
(the “NuDevco Note”). The Company did not retain any of the net proceeds from the Offering. The Company recorded
$2.7 million
of previously deferred incremental costs directly attributable to the Offering as a reduction in equity at the Offering date, which were funded by the Offering proceeds.
The Company also issued
10,750,000
shares of Class B common stock, par value
0.01
per share (the “Class B common stock”) to Spark HoldCo,
10,612,500
of which Spark HoldCo distributed to NuDevco Retail Holdings, and
137,500
of which Spark HoldCo distributed to NuDevco Retail.
At the consummation of the Offering, the Company's outstanding common stock is summarized in the table below:
|
|
|
|
|
|
|
|
|
|
Shares of
|
|
|
common stock
|
|
|
Number
|
|
Percent Voting Interest
|
Publicly held Class A common stock
|
|
3,000,000
|
|
|
21.82
|
%
|
Class B common stock held by NuDevco Retail Holdings, LLC and NuDevco Retail, LLC
|
|
10,750,000
|
|
|
78.18
|
%
|
Total
|
|
13,750,000
|
|
|
100.00
|
%
|
Credit Facility
Concurrently with the closing of the Offering, the Company entered into a new
$70.0 million
senior secured credit facility (“Senior Credit Facility”). See Note 4 “Long-Term Debt” for further discussion.
Exchange and Registration Rights
NuDevco has the right to exchange (the “Exchange Right”) all or a portion of its Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or cash at Spark Energy, Inc.’s or Spark HoldCo’s election (the “Cash Option”)) at an exchange ratio of one share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B common stock) exchanged. In addition, NuDevco has the right, under certain circumstances, to cause the Company to register the offer and resale of NuDevco's shares of Class A common stock obtained pursuant to the Exchange Right.
Tax Receivable Agreement
Concurrently with the closing of the Offering, the Company entered into a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. See Note 11 “Transactions with Affiliates” for further discussion.
Other Transactions in Connection with the Consummation of the Offering
In connection with the Offering the following restructuring transactions occurred:
|
|
•
|
SEG and SE were converted from limited partnerships into limited liability companies;
|
|
|
•
|
SEG, SE and an affiliate entered into an interborrower agreement, pursuant to which such affiliate agreed to be solely responsible for
$29.0 million
of the outstanding indebtedness. SE and SEG repaid their outstanding indebtedness of
$10.0 million
and borrowed
$10.0 million
under the Company's Senior Credit Facility,
|
|
|
•
|
NuDevco Retail Holdings contributed all of its interests in SEG and SE to Spark HoldCo in exchange for all of the outstanding units of Spark HoldCo and transferred
1%
of those Spark HoldCo units to NuDevco Retail;
|
|
|
•
|
NuDevco Retail Holdings transferred Spark HoldCo units to the Company for the
$50,000
NuDevco Note and the limited liability company agreement of Spark HoldCo was amended and restated to admit the Company as its sole managing member.
|
Following the Offering, the Company purchased
2,997,222
Spark HoldCo units from NuDevco Retail Holdings and repaid the NuDevco Note. The
2,997,222
Spark Holdco units we purchased with the proceeds from the Offering, together with the
2,778
Spark HoldCo units we purchased in exchange for the NuDevco Note prior to the Offering, represent a
21.82%
ownership interest in Spark HoldCo. After giving effect to these transactions and the Offering, the Company owns an approximate
21.82%
interest in Spark HoldCo. NuDevco Retail Holdings owns an approximate
77.18%
interest in Spark HoldCo and
10,612,500
shares of Class B common stock, and NuDevco Retail owns a
1%
interest in Spark HoldCo and
137,500
shares of Class B common stock.
Each share of Class B common stock, all of which is held by NuDevco, has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.
2. Basis of Presentation and Summary of Significant Accounting Policies
The accompanying combined and consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). All significant intercompany transactions and balances have been eliminated in the combined and consolidated financial statements.
The accompanying combined and consolidated financial statements have been prepared in accordance with Regulation S-X, Article 3,
General Instructions as to Financial Statements and Staff
Accounting Bulletin (“SAB”) Topic 1-B, Allocations of Expenses and Related Disclosures in Financial
Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity
on a stand-alone basis and are derived from SE’s and SEG’s historical basis in the assets and liabilities before the Offering and Spark Energy Inc.’s financial results after the Offering, and include all revenues, costs, assets and liabilities attributable to the retail natural gas and asset optimization and retail electricity businesses of SE and SEG for the periods prior to the Offering that are specifically identifiable or have been allocated to the Company. Management has made certain assumptions and estimates in order to allocate a reasonable share of expenses to the Company, such that the Company’s combined and consolidated financial statements reflect substantially all of its costs of doing business. The Company also enters into transactions with and pays certain costs on behalf of affiliates under common control in order to reduce
risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. The Company direct bills certain expenses incurred on behalf of affiliates or allocates certain overhead expenses to affiliates associated with general and administrative services based on services provided, departmental usage, or headcount, which are considered reasonable by management. The allocations and related estimates and assumptions are described more fully in Note 11 “Transactions with Affiliates”. These costs are not necessarily indicative of the cost that the Company would have incurred had it operated as an independent stand-alone entity prior to the Offering. Affiliates have also relied upon Spark Energy Ventures as a participant in the credit facility for periods prior to the Offering as described more fully in Note 4 “Long-Term Debt”. As such, the Company’s combined and consolidated financial statements do not fully reflect what the Company’s financial position, results of operations and cash flows would have been had the Company operated as an independent stand-alone company prior to the Offering. As a result, historical financial information prior to the Offering is not necessarily indicative of what the Company’s results of operations, financial position and cash flows will be in the future. The Company’s combined and consolidated financial statements include all wholly-owned and controlled subsidiaries.
Cash and Cash Equivalents
Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Company periodically assesses the financial condition of the institutions where these funds are held and believes that its credit risk is minimal with respect to these institutions.
Restricted Cash
Restricted cash consists of cash that has been placed in escrow for a contractually designated future use. As of December 31, 2014, the Company had
$0.7 million
in restricted cash related to future required payments for customer acquisitions as described in more detail in Note 13 “Customer Acquisitions”. The restricted cash is classified as current as the payments for these customers are expected to be made in the first quarter of 2015. There was no restricted cash as of December 31, 2013.
Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Accounts receivable in the combined and consolidated balance sheets are net of allowance for doubtful accounts of
$8.0 million
and
$1.2 million
as of December 31, 2014 and 2013, respectively.
The Company accrues an allowance for doubtful accounts based upon estimated uncollectible accounts receivable considering historical collections, accounts receivable aging analysis, credit risk and other factors. The Company writes off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is deemed to be uncollectible. Bad debt expense of
$10.2 million
,
$3.1 million
and
$1.8 million
was recorded in general and administrative expense in the combined and consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively.
The Company conducts business in many utility service markets where the local regulated utility is responsible for billing the customer, collecting payment from the customer and remitting payment to the Company (“POR programs”). This POR service results in substantially all of the Company’s credit risk being linked to the applicable utility, which generally has an investment-grade rating, and not to the end-use customer. The Company monitors the financial condition of each utility and currently believes that its susceptibility to an individually significant write-off as a result of concentrations of customer accounts receivable with those utilities is remote. Trade accounts receivable that are part of a local regulated utility’s POR program are recorded on a gross basis in accounts receivable in the combined and consolidated balance sheets. The discount paid to the local regulated utilities is recorded in general and administrative expense in the combined and consolidated statements of operations.
In markets that do not offer POR services or when the Company chooses to directly bill its customers, certain receivables are billed and collected by the Company. The Company bears the credit risk on these accounts and records an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. The Company’s customers are individually insignificant and geographically dispersed in these markets. The Company writes off customer balances when it believes that amounts are no longer collectible and when it has exhausted all means to collect these receivables.
Inventory
Inventory consists of natural gas used to fulfill and manage seasonality for fixed and variable-price retail customer load requirements and is valued at the lower of weighted average cost or market. Purchased natural gas costs are recognized in the combined and consolidated statements of operations, within retail cost of revenues, when the natural gas is sold and delivered out of the storage facility. There were no inventory impairments recorded for the years ended December 31, 2014, 2013 and 2012. When natural gas is sold costs are recognized in the combined and consolidated statements of operations, within retail cost of revenues, at the weighted average cost value at the time of the sale.
Customer Acquisition Costs
The Company has retail natural gas and electricity customer acquisition costs, net of
$12.4 million
and
$4.8 million
recorded in current assets and
$3.0 million
and
$2.9 million
recorded in noncurrent assets representing direct response advertising costs as of December 31, 2014 and 2013, respectively. Customer acquisition costs is spending for organic customer acquisitions and does not include customer acquisitions through merger and acquisition activities, which are recorded as intangible assets. Amortization of customer acquisition costs, recorded in depreciation and amortization in the combined and consolidated statements of operations, was
$18.5 million
,
$10.1 million
and
$16.4 million
for the years ended December 31, 2014, 2013 and 2012, respectively. Capitalized direct response advertising costs consist primarily of hourly and commission based telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven customer generation, and are capitalized and amortized over the estimated
two
-year average life of a customer in accordance with the provisions of FASB ASC 340-20,
Capitalized Advertising Costs
.
Recoverability of customer acquisition costs is evaluated based on a comparison of the carrying amount of the customer acquisition costs to the future net cash flows expected to be generated by the customers acquired, considering specific assumptions for customer attrition, per unit gross profit, and operating costs. These assumptions are based on forecasts and historical experience.
Based on the analysis described above, for the year ended December 31, 2014, the Company recorded accelerated amortization of such costs of
$6.5 million
associated with capitalized customer acquisition costs in California and
$0.2 million
associated with capitalized customer acquisition costs in Massachusetts. This accelerated amortization expense is included in “depreciation and amortization” on the statement of operations. There were no such accelerated amortization charges recorded for the year ended December 31, 2013 and 2012.
Intangibles - Customer Acquisitions
Customer acquisitions through merger and acquisition activities are recorded as intangible assets and represent customer contract acquisitions not acquired through the direct response advertising discussed above at “
Customer Acquisition Costs
”. The Company has recorded
$1.5 million
, net of amortization, as of December 31, 2014 related to these intangible assets. These intangibles are amortized over the estimated
three
-year average life of the related customer contracts acquired.
We review intangible assets for impairment whenever events or changes in business circumstances indicate the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an
impairment exists, a loss would be recognized for the difference between the fair value and carrying value of the intangible assets. No impairments of intangible assets were recorded in 2014, 2013 and 2012.
Deferred Financing Costs
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense using the straight-line method over the life of the related long-term debt due to the variable nature of the Company’s long-term debt.
Property and Equipment
The Company records property and equipment at historical cost. Depreciation expense is recorded on a straight-line method based on estimated useful lives. When assets are placed into service, management makes estimates with respect to useful lives and salvage values of the assets.
When items of property and equipment are sold or otherwise disposed of, any gain or loss is recorded in the combined and consolidated statements of operations.
The Company capitalizes costs associated with internal-use software projects in accordance with FASB ASC Topic 350-40,
Internal-Use Software
. Capitalized costs are the costs incurred during the application development stage of the internal-use software project such as software configuration, coding, installation of hardware and testing. Costs incurred during the preliminary or post-implementation stage of the internal-use software project are expensed in the period incurred. These types of costs include formulation of ideas and alternatives, training and application maintenance. After internal-use software projects are completed, the associated capitalized costs are depreciated over the estimated useful life of the related asset. Interest costs incurred while developing internal-use software projects are capitalized in accordance with FASB ASC Topic 835-20,
Capitalization of Interest
. Capitalized interest costs for the years ended December 31, 2014, 2013 and 2012 were not material.
Segment Reporting
The FASB ASC Topic 280,
Segment Reporting
, established standards for entities to report information about the operating segments and geographic areas in which they operate. The Company operates
two
segments, retail natural gas and retail electricity, and all of its operations are located in the United States.
Revenues and Cost of Revenues
The Company’s revenues are derived primarily from the sale of natural gas and electricity to retail customers. The company also records revenue from sales of natural gas and electricity to wholesale counterparties, including affiliates. Revenues are recognized by the Company using the following criteria: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the buyer’s price is fixed or determinable and (4) collection is reasonably assured. Utilizing these criteria, revenue is recognized when the natural gas or electricity is delivered. Similarly, cost of revenues is recognized when the commodity is delivered.
Revenues for natural gas and electricity sales are recognized upon delivery under the accrual method. Natural gas and electricity sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
The Company records gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the years ended December 31, 2014, 2013 and 2012, the Company’s retail revenues and retail cost of revenues included gross receipts taxes of
$3.0 million
,
$3.5 million
and
$5.1 million
, respectively.
Costs for natural gas and electricity sales are recognized as the commodity is delivered to the customer under the accrual method. Natural gas and electricity costs that have not been billed to the Company by suppliers but have been incurred by period end are estimated. The Company estimates volumes for natural gas and electricity delivered based on the forecasted revenue volumes, estimated transportation cost volumes and estimation of other costs associated with retail load which varies by commodity utility territory. These costs include items like ISO fees, ancillary services and renewable energy credits. Estimated amounts are adjusted when actual usage is known and billed.
The Company’s asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage and transportation opportunities, meet the definition of trading activities and are recorded on a net basis in the combined and consolidated statements of operations in net asset optimization revenues pursuant to FASB ASC 815,
Derivatives and Hedging
. The Company recorded asset optimization revenues, primarily related to physical sales or purchases of commodities, of
$284.6 million
,
$192.4 million
and
$248.6 million
for the years ended December 31, 2014, 2013 and 2012, respectively, and recorded asset optimization costs of revenues of
$282.3 million
,
$192.1 million
and
$249.7 million
for the years ended December 31, 2014, 2013 and 2012, respectively, which are presented on a net basis in asset optimization revenues.
Natural Gas Imbalances
The combined and consolidated balance sheets include natural gas imbalance receivables and payables, which primarily results when customers consume more or less gas than has been delivered by the Company to local distribution companies (“LDCs”). The settlement of natural gas imbalances varies by LDC, but typically the natural gas imbalances are settled in cash or in kind on a monthly, quarterly, semi-annual or annual basis. The imbalances are valued at an estimated net realizable value. The Company recorded an imbalance receivable of
$1.4 million
and
$0.7 million
recorded in other current assets on the combined and consolidated balance sheets as of December 31, 2014 and 2013, respectively. The Company recorded an imbalance payable of
$0.6 million
and
zero
recorded in other current liabilities on the combined and consolidated balance sheets as of December 31, 2014 and 2013, respectively.
Fair Value
FASB ASC 820,
Fair Value Measurement
, established a single authoritative definition of fair value, set out a framework for measuring fair value, and requires disclosures about fair value measurements. The standard clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The standard utilizes a fair value hierarchy that prioritizes the inputs to the valuation techniques used to measure fair value into three broad levels based on quoted prices in active market, observable market prices, and unobservable market prices.
When the Company is required to measure fair value, and there is not a quoted or observable market price for a similar asset or liability, the Company utilizes the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions.
Derivative Instruments
The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of its business operations.
All derivatives, other than those for which an exception applies, are recorded in the combined and consolidated balance sheets at fair value. Derivative instruments representing unrealized gains are reported as derivative assets while derivative instruments representing unrealized losses are reported as derivative liabilities. The Company has elected to offset amounts in the combined and consolidated balance sheets for derivative instruments executed with the same counterparty under a master netting arrangement. One of the exceptions to fair value accounting, normal
purchases and normal sales, has been elected by the Company for certain derivative instruments when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable and is expected to be used in normal course of business. Retail revenues and retail cost of revenues resulting from deliveries of commodities under normal purchase contracts and normal sales contracts are included in earnings at the time of contract settlement.
To manage commodity price risk, the Company holds certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Company does not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. As part of the Company’s strategy to optimize its assets and manage related commodity risks, it also manages a portfolio of commodity derivative instruments held for trading purposes. The Company uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses derivative instruments to reduce risk by generally creating offsetting market positions.
Changes in the fair value of and amounts realized upon settlement of derivative instruments not held for trading purposes are recognized currently in earnings in retail revenues or retail costs of revenues, respectively.
Changes in the fair value of and amounts realized upon settlement of derivative instruments held for trading purposes are recognized currently in earnings in net asset optimization revenues.
The Company has historically designated a portion of our derivative instruments as cash flow hedges for accounting purposes. For all hedging transactions, the Company formally documented the hedging transaction and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk was assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Company also formally assessed, both at the inception of the hedging transaction and on an ongoing basis, whether the derivatives used in hedging transactions were highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that were designated and qualified as part of a cash flow hedging transaction, the effective portion of the gain or loss on the derivative was reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during when the hedged transaction affected earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness were recognized in current earnings. Hedge accounting was discontinued prospectively for derivatives that ceased to be highly effective hedges or when the occurrence of the forecasted transaction was no longer probable.
Effective July 1, 2013, the Company elected to discontinue hedge accounting prospectively and began to record the changes in fair value recognized in the combined and consolidated statement of operations in the period of change. Because the underlying transactions were still probable of occurring, the related accumulated OCI was frozen and recognized in earnings as the underlying hedged item was delivered. As of December 31, 2014 and 2013, the Company has no gains or losses on derivatives that were designated as qualifying cash flow hedging transactions recorded as a component of accumulated OCI, as all previously deferred gains and losses on qualifying hedge transactions were reclassified into earnings during the year ended December 31, 2013 and 2012 when the associated hedged transactions were recorded into earnings.
Income Taxes
The Company recognizes the amount of taxes payable or refundable for the year. In addition, the Company follows the asset and liability method of accounting for income taxes where deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in those years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in
income in the period that includes the enactment date. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences.
The Company recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.
Earnings per Share
Basic earnings per share (“EPS”) is computed by dividing net income attributable to shareholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they have no economic interest in the Company. Diluted earnings per share is similarly calculated except that the denominator is increased (1) using the treasury stock method to determine the potential dilutive effect of the Company’s outstanding unvested restricted stock units and (2) using the if-converted method to determine the potential dilutive effect of the Company’s Class B common stock. The Company has omitted earnings per share prior to the Offering because the Company operated under a sole member equity structure for those periods.
Non-controlling Interest
As a result of the Offering, the Company acquired a
21.82%
economic interest in Spark HoldCo, and is the sole managing member in Spark HoldCo, with NuDevco Retail Holdings, LLC and NuDevco Retail, LLC (collectively, “NuDevco”) retaining a
78.18%
economic interest in Spark HoldCo. As a result, the Company has consolidated the financial position and results of operations of Spark HoldCo and reflected the economic interest retained by NuDevco as a non-controlling interest. Net income attributable to non-controlling interest for the year ended December 31, 2014 represents the net income attributable to NuDevco prior to the Offering and NuDevco’s retained interest subsequent to the Offering.
Commitments and Contingencies
The Company enters into various firm purchase and sale commitments for natural gas, storage, transportation, and electricity that do not meet the definition of a derivative instrument or for which the Company has elected the normal purchase or normal sales exception. Management does not anticipate that such commitments will result in any significant gains or losses based on current market conditions.
Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.
Transactions with Affiliates
The Company enters into transactions with and incurs certain costs on behalf of affiliates that are commonly controlled by NuDevco Partners Holdings in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. These transactions include, but are not limited to, certain services to the affiliated companies associated with the Company’s debt facility prior to the Offering, employee benefits provided through the Company’s benefit plans, insurance plans, leased office
space, and administrative salaries for accounting, tax, legal, or technology services. As such, the accompanying combined and consolidated financial statements include costs that have been incurred by the Company and then directly billed or allocated to affiliates and are recorded net in general and administrative expense on the combined and consolidated statements of operations with a corresponding accounts receivable-affiliates recorded in the combined and consolidated balance sheets. Additionally, the Company enters into transactions with certain affiliates for sales or purchases of natural gas and electricity, which are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the combined and consolidated statements of operations with a corresponding accounts receivable-affiliate or accounts payable-affiliate in the combined and consolidated balance sheets. See Note 11, “Transactions with Affiliates” for further discussion.
Use of Estimates and Assumptions
The preparation of the Company’s combined and 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 combined financial statements and the reported amounts of revenues and expenses during the period. Actual results could materially differ from those estimates. Significant items subject to such estimates by the Company’s management include estimates for unbilled revenues and related cost of revenues, provisions for uncollectible receivables, valuation of customer acquisition costs, estimated useful lives of property and equipment, valuation of derivatives and reserves for contingencies.
Subsequent Events
Subsequent events have been evaluated through the date these financial statements are issued. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the combined and consolidated financial statements. See Note 14 “Subsequent Events” for further discussion.
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09,
Revenue from Contracts with Customers
, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.
In August 2014, the FASB issued ASU No. 2014-15, P
resentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern
(“ASU 2014-15”). The new guidance clarifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosure. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. The Company does not expect the adoption to have a material effect on the combined or consolidated financial statements.
In November 2014, the FASB issued ASU No. 2014-16,
Derivatives and Hedging
, which clarifies how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The amendments in this Update are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Update does not change the current criteria in GAAP for determining when separation of certain embedded derivative features in a hybrid financial instrument is required. The Company does not believe the adoption of this ASU to have a material impact on the combined and consolidated financial statements.
In February 2015, the FASB issued ASU No. 2015-02,
Consolidation
(Topic 810)
(“ASU 2015-02”). The new guidance changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption at an interim period. The Company has not yet determined the effect of the standard on its ongoing financial reporting.
3. Property and Equipment
Property and equipment consist of the following amounts as of (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
useful
lives (years)
|
|
December 31, 2014
|
|
December 31, 2013
|
Information technology
|
2 – 5
|
|
$
|
25,588
|
|
|
$
|
22,529
|
|
Leasehold improvements
|
2 – 5
|
|
4,568
|
|
|
4,568
|
|
Furniture and fixtures
|
2 – 5
|
|
998
|
|
|
998
|
|
Total
|
|
|
31,154
|
|
|
28,095
|
|
Accumulated depreciation
|
|
|
(26,933
|
)
|
|
(23,278
|
)
|
Property and equipment—net
|
|
|
$
|
4,221
|
|
|
$
|
4,817
|
|
Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of
December 31,
2014
and
2013
, information technology includes
$0.4 million
and
$1.3 million
, respectively, of costs associated with assets not yet placed into service.
Depreciation expense recorded in the combined and consolidated statements of operations was
$3.7 million
,
$6.1 million
and
$6.4 million
for the years ended
December 31,
2014
,
2013
and 2012, respectively.
4. Long-Term Debt
In October 2007, Spark Energy Ventures and all of its subsidiaries (collectively, the “Borrowers”), entered into a credit agreement, consisting of a working capital facility, a term loan and a revolving credit facility (the “Credit Agreement”), with SE and SEG as co-borrowers under which they were jointly and severally liable for amounts Borrowers borrowed under the Credit Agreement. The Credit Agreement was secured by substantially all of the assets of Spark Energy Ventures and its subsidiaries.
The Credit Agreement was amended on May 30, 2008 to provide for a
$177.5 million
working capital facility, a
$100 million
term loan, and a
$35 million
revolving credit facility. On January 24, 2011, the Borrowers amended and restated the Credit Agreement (the “Fifth Amended Credit Agreement”) to decrease the working capital facility to
$150 million
, to increase the term loan to
$130 million
and to eliminate the revolving credit facility.
On December 17, 2012, the Borrowers amended and restated the Fifth Amended Credit Agreement to decrease the working capital facility to
$70 million
, to decrease the term loan to
$125 million
and to reinstate the revolving credit facility in the amount of
$30 million
(the “Sixth Amended Credit Agreement”).
On July 31, 2013 and in conjunction with the initial public offering of Marlin Midstream Partners, LP (“Marlin”), which was formerly a wholly owned subsidiary of Spark Energy Ventures, the Sixth Amended Credit Agreement was amended and restated to increase the working capital facility to
$80 million
and eliminate the term loan and revolving credit facility (the “Seventh Amended Credit Agreement”) and to remove Marlin as a party to the Credit Agreement. The Seventh Amended Credit Agreement continued to be secured by the assets of Spark Energy Ventures and its subsidiaries through completion of the Offering.
Although SE and SEG, as wholly owned subsidiaries of Spark Energy Ventures, were jointly and severally liable for Marlin’s borrowing under the Sixth Amended Credit Agreement prior to the Marlin initial public offering, SE and SEG did not historically have access to or use the term loan and the revolving credit facility utilized by Marlin. SE and SEG were the primary recipients of the proceeds from the working capital facility.
The Company adopted ASU 2013-04, which prescribes the accounting for joint and several liability arrangements early and applied the accounting in the guidance combined and consolidated financial statements prior to the Offering as required by the standard. This guidance requires an entity to measure its obligation resulting from joint and several liability arrangements for which the total amount under the arrangement is fixed at the reporting date, as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. Based on the Sixth Amended Credit Agreement prior to the Marlin initial public offering and understanding among the Borrowers, the term loan and the revolving credit facility were assigned specifically to Marlin. The Company has recognized the proceeds from the working capital facility in its combined financial statements prior to the Offering, which represented the amounts the Company with the other Borrowers agreed to pay, and the amounts the Company expected to pay.
Working Capital Facility
The working capital facility was
$150 million
in 2012 under the Fifth Amended Credit Agreement and was later amended to
$70 million
on December 17, 2012 under the Sixth Amended Credit Agreement. On July 31, 2013, and in conjunction with the Seventh Amended Credit Agreement, the working capital facility was increased to
$80 million
.
The working capital facility was available for use by Spark Energy Ventures and its affiliates to finance the working capital requirements related to the purchase and sale of natural gas, electricity, and other commodity products not related to the retail natural gas and asset optimization and retail electricity businesses of the Company. The Company’s combined financial statements include the total amounts outstanding under the working capital facility of
$27.5 million
as of December 31, 2013, which is classified as current in the combined and consolidated balance sheet as the working capital facility was drawn upon and repaid on a monthly basis to fund working capital needs. Portions of the borrowings were used to fund equity distributions to the sole member of the Company to fund unrelated operations of an affiliate under the common control of the sole member prior to the Offering. The total amounts outstanding under the facility as of
December 31, 2013
and through the Offering date included
$29.0 million
that was retained and paid off by an affiliate in connection with the Offering.
Further, through the issuance of letters of credit, the Company was able to secure payment to suppliers. No obligation is recorded for such outstanding letters of credit unless they are drawn upon by the suppliers and in the event a supplier draws on a letter of credit, repayment is due by the earlier of demand by the bank or at the expiration of the applicable Credit Agreement. Letters of credit issued and outstanding as of
December 31,
2013 were
$10.0 million
.
Under the working capital facility, the Company paid a fee with respect to each letter of credit issued and outstanding. For the years ended
December 31,
2014
,
2013
and 2012, the Company incurred fees on letters of credit issued and outstanding totaling
$0.4 million
,
$0.5 million
and
$0.6 million
, respectively, which is recorded in interest expense in the combined and consolidated statements of operations.
Under the Sixth Amended Credit Agreement, the Company was able to elect to have loans under the working credit facility bear interest either (i) at a Eurodollar-based rate plus a margin ranging from
3.00%
to
3.75%
depending on the Company’s consolidated funded indebtedness ratio then in effect, or (ii) at a base rate loan plus a margin ranging from
2.00%
to
2.75%
depending on the Company’s consolidated funded indebtedness ratio then in effect. The Company also paid a nonutilization fee equal to
0.50%
per annum.
Under the Seventh Amended Credit Agreement, the Company was able to elect to have loans under the working capital facility bear interest (i) at a Eurodollar-based rate plus a margin ranging from
3.00%
to
3.25%
, depending on the Spark Energy Ventures’ aggregate amount outstanding then in effect, (ii) at a base rate loan plus a margin
ranging from
2.00%
to
2.25%
, depending on Spark Energy Ventures’ aggregate amount outstanding then in effect or (iii) a cost of funds rate loan plus a margin ranging from
2.50%
to
2.75%
, depending on Spark Energy Ventures’ aggregate amount outstanding then in effect. Each working capital loan made as a result of a drawing under a letter of credit bears interest on the outstanding principal amount thereof from the date funded at a floating rate per annum equal to the cost of funds rate plus the applicable margin until such loan has been outstanding for more than two business days and, thereafter, bears interest on the outstanding principal amount thereof at a floating rate per annum equal to the base rate plus the applicable margin, plus two percent
2.00%
per annum. The Company incurred interest expense related to our revolving credit facilities of
$0.4 million
,
$0.3 million
and
$1.3 million
for the years ended
December 31, 2014
,
2013
and 2012, respectively, which is recorded in interest expense in the combined and consolidated statements of operations.
The Company also paid a commitment fee equal to
0.50%
per annum. The Company incurred commitment fees from the prior and current facilities totaling
$0.1 million
,
$0.2 million
and
$0.5 million
for the years ended
December 31, 2014
,
2013
and 2012, which is recorded in interest expense in the combined and consolidated statements of operations.
Deferred Financing Costs
Deferred financing costs were
$0.3 million
(all of which represents capitalized financing costs related to the new Senior Credit Facility entered into on August 1, 2014) and
$0.5 million
as of
December 31, 2014
and
2013
, respectively. Of these amounts,
$0.2 million
and
$0.4 million
is recorded in other current assets in the combined and consolidated balance sheets as of
December 31, 2014
and
2013
, respectively, and
$0.1 million
and
$0.1 million
is recorded in other assets in the combined and consolidated balance sheets as of
December 31, 2014
and
2013
, respectively, based on the terms of the working capital facilities.
Amortization and write offs of deferred financing costs were
$0.6 million
(which included
$0.3 million
of deferred financing costs written off upon extinguishment of the Seventh Amended Credit Facility),
$0.7 million
(which included
$0.1 million
of deferred financing costs written off in connection with the execution of the Seventh Amended Credit Facility), and
$0.9 million
(which included
$0.3 million
of deferred financing costs written off in connection with the execution of the Sixth Amended Credit Facility), for the years ended
December 31, 2014
,
2013
and 2012, respectively, which is recorded in interest expense in the combined and consolidated statements of operations.
NuDevco Note
NuDevco Retail Holdings transferred Spark HoldCo units to the Company for the
$50,000
NuDevco Note, and the limited liability company agreement of Spark HoldCo was amended and restated to admit Spark Energy, Inc. as its sole managing member. This promissory note was repaid in connection with proceeds from the Offering.
New Credit Facility
Concurrently with the closing of the Offering, the Company entered into the
$70.0 million
Senior Credit Facility, which matures on August 1, 2016. If no event of default has occurred, the Company has the right, subject to approval by the administrative agent and each issuing bank, to increase the commitments under the Senior Credit Facility up to
$120.0 million
. The Company borrowed approximately
$10.0 million
under the Senior Credit Facility at the closing of the Offering to repay in full the outstanding indebtedness under the Seventh Amended Credit Agreement that SEG and SE agreed to be responsible for pursuant to an interborrower agreement between SEG, SE and an affiliate. The remaining
$29.0 million
of indebtedness outstanding under the Seventh Amended Credit Agreement at the Offering date was paid down by our affiliate with its own funds concurrent with the closing of the Offering pursuant to the terms of the interborrower agreement. Following this repayment, the Seventh Amended Credit Agreement was terminated. The Company had
$15 million
in letters of credit issued under the Senior Credit Facility at inception. As of
December 31, 2014
, the Company had
$33.0 million
outstanding under the Senior Credit Facility and
$10.7 million
in letters of credit issued. The Senior Credit Facility is available to fund expansions, acquisitions and working capital requirements for operations and general corporate purposes.
At our election, interest under the Senior Credit Facility is generally determined by reference to:
|
|
•
|
the Eurodollar-based rate plus a margin ranging from
2.75%
to
3.00%
, depending on the overall utilization of the working capital facility;
|
|
|
•
|
the alternate base rate loan plus a margin ranging from
1.75%
to
2.00%
, depending on the overall utilization of the working capital facility; or
|
|
|
•
|
a cost of funds rate loan plus a margin ranging from
2.25%
to
2.50%
, depending on the overall utilization of the working capital facility.
|
The interest rate is generally reduced by
25 basis points
if utilization under the Senior Credit Facility is below fifty percent.
Each working capital loan made as a result of a drawing under a letter of credit or a reducing letter of credit borrowing bears interest on the outstanding principal amount thereof from the date funded at a floating rate per annum equal to the base rate plus the applicable margin until such loan has been outstanding for more than two business days and, thereafter, bears interest on the outstanding principal amount thereof at a floating rate per annum equal to the base rate plus the applicable margin, plus two percent (
2.00%
) per annum. Additionally, the Company is charged a letter of credit fee for letters of credit outstanding. Our fee is from
2.00%
to
2.50%
per annum, depending on the overall utilization of the working capital facility and what type of transaction it supports.
We pay an annual commitment fee of
0.375%
or
0.5%
on the unused portion of the Senior Credit Facility depending upon the unused capacity. The lending syndicate under the Senior Credit Facility is entitled to several additional fees including an upfront fee, annual agency fee, and fronting fees based on a percentage of the face amount of letters of credit payable to any syndicate member that issues a letter a credit. Commitment fees were immaterial for the year ended December 31, 2014. The Company paid no commitment fees related to the Senior Credit Facility for the years ended December 31, 2013 and 2012.
The Company incurred total interest expense related to prior and current credit facilities of
$1.6 million
,
$1.7 million
and
$3.4 million
for the years ended
December 31, 2014
,
2013
and 2012, respectively.
The Senior Credit Facility is secured by the membership interests of SE, SEG and the equity of the Co-Borrowers’ present and future subsidiaries, all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.
The Senior Credit Facility contains covenants which, among other things, require the Company to maintain certain financial ratios or conditions. At all times, the Company must maintain net working capital, tangible net worth and a leverage ratio to a certain threshold. The Senior Credit Facility also contains negative covenants that limit our ability to, among other things, make certain payments, distributions, investments, acquisitions or loans.
In addition, the Senior Credit Facility contains affirmative covenants that are customary for credit facilities of this type. The covenants include delivery of financial statements, including any filings made with the SEC, maintenance of property and insurance, payment of taxes and obligations, material compliance with laws, inspection of property, books and records and audits, use of proceeds, payments to bank blocked accounts, notice of defaults and certain other customary matters.
5. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of
counterparties involved and the impact of credit enhancements but also the impact of the Company’s own nonperformance risk on its liabilities.
The Company applies fair value measurements to its commodity derivative instruments based on the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
|
|
•
|
Level 1—Quoted prices in active markets for identical assets and liabilities. Instruments categorized in Level 1 primarily consist of financial instruments such as exchange-traded derivative instruments.
|
|
|
•
|
Level 2—Inputs other than quoted prices recorded in Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active 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. 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.
Non-Derivative Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable, accounts receivable-affiliates, accounts payable, accounts payable-affiliates, and accrued liabilities recorded in the combined and consolidated balance sheets approximate fair value due to the short-term nature of these items. The carrying amount of long-term debt recorded in the combined and consolidated balance sheets approximates fair value because of the variable rate nature of the Company’s long-term debt. The fair value of the payable pursuant to tax receivable agreement-affiliate is not determinable due to the affiliate nature and terms of the associated agreement with the affiliate.
Derivative Instruments
The following tables present assets and liabilities measured and recorded at fair value in the Company’s combined and consolidated balance sheets on a recurring basis by and their level within the fair value hierarchy as of (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
December 31, 2014
|
|
|
|
|
|
|
|
Non-trading commodity derivative assets
|
$
|
—
|
|
|
$
|
80
|
|
|
$
|
—
|
|
|
$
|
80
|
|
Trading commodity derivative assets
|
—
|
|
|
136
|
|
|
—
|
|
|
136
|
|
Total commodity derivative assets
|
$
|
—
|
|
|
$
|
216
|
|
|
$
|
—
|
|
|
$
|
216
|
|
Non-trading commodity derivative liabilities
|
$
|
(6,810
|
)
|
|
$
|
(5,017
|
)
|
|
$
|
—
|
|
|
$
|
(11,827
|
)
|
Trading commodity derivative liabilities
|
(32
|
)
|
|
(145
|
)
|
|
—
|
|
|
(177
|
)
|
Total commodity derivative liabilities
|
$
|
(6,842
|
)
|
|
$
|
(5,162
|
)
|
|
$
|
—
|
|
|
$
|
(12,004
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
December 31, 2013
|
|
|
|
|
|
|
|
Non-trading commodity derivative assets
|
$
|
—
|
|
|
$
|
4,672
|
|
|
$
|
—
|
|
|
$
|
4,672
|
|
Trading commodity derivative assets
|
—
|
|
|
3,405
|
|
|
—
|
|
|
3,405
|
|
Total commodity derivative assets
|
$
|
—
|
|
|
$
|
8,077
|
|
|
$
|
—
|
|
|
$
|
8,077
|
|
Non-trading commodity derivative liabilities
|
$
|
(563
|
)
|
|
$
|
(854
|
)
|
|
$
|
—
|
|
|
$
|
(1,417
|
)
|
Trading commodity derivative liabilities
|
147
|
|
|
(581
|
)
|
|
—
|
|
|
(434
|
)
|
Total commodity derivative liabilities
|
$
|
(416
|
)
|
|
$
|
(1,435
|
)
|
|
$
|
—
|
|
|
$
|
(1,851
|
)
|
The Company had no financial instruments measured using level 3 at
December 31, 2014
and 2013. The Company had no transfers of assets or liabilities between any of the above levels during the
year ended
December 31, 2014
and 2013.
The Company’s derivative contracts include exchange-traded contracts fair valued utilizing readily available quoted market prices and non-exchange-traded contracts fair valued using market price quotations available through brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of the Company’s derivative contracts, the Company applies a credit risk valuation adjustment to reflect credit risk which is calculated based on the Company’s or the counterparty’s historical credit risks. As of
December 31, 2014
and
December 31, 2013
, the credit risk valuation adjustment was not material.
6. Accounting for Derivative Instruments
The Company is exposed to the impact of market fluctuations in the price of electricity and natural gas and basis costs, storage and ancillary capacity charges from independent system operators. The Company uses derivative instruments to manage exposure to these risks, and historically designated certain derivative instruments as cash flow hedges for accounting purposes. For derivatives designated in a qualifying cash flow hedging relationship, the effective portion of the change in fair value is recognized in accumulated other comprehensive income (“OCI
”
) and reclassified to earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in earnings.
The Company also holds certain derivative instruments that are not held for trading purposes but are also not designated as hedges for accounting purposes. These derivative instruments represent economic hedges that mitigate the Company’s exposure to fluctuations in commodity prices. For these derivative instruments, changes in the fair value are recognized currently in earnings in retail revenues or retail costs of revenues, respectively.
As part of the Company’s strategy to optimize its assets and manage related risks, it also manages a portfolio of commodity derivative instruments held for trading purposes. The Company’s commodity trading activities are subject to limits within the Company’s Risk Management Policy. For these derivative instruments, changes in the fair value are recognized currently in earnings in net asset optimization revenues.
Derivative assets and liabilities are presented net in the Company’s combined and consolidated balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. The Company’s derivative contracts include transactions that are executed both on an exchange and centrally cleared as well as over-the-counter, bilateral contracts that are transacted directly with a third party. To the extent the Company has paid or received collateral related to the derivative assets or liabilities, such amounts would be presented net against the related derivative asset or liability’s fair value. As of
December 31, 2014
and 2013, the Company had not paid or received any collateral amounts. The specific types of derivative instruments the Company may execute to manage the commodity price risk include the following:
•
Forward contracts, which commit the Company to purchase or sell energy commodities in the future;
•
Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;
•
Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined notional quantity; and,
•
Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity.
The Company has entered into other energy-related contracts that do not meet the definition of a derivative instrument or qualify for the normal purchase or normal sale exception and are therefore not accounted for at fair value including the following:
•
Forward electricity and natural gas purchase contracts for retail customer load; and,
•
Natural gas transportation contracts and storage agreements.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of the Company’s open derivative financial instruments accounted for at fair value, broken out by commodity, as of:
Non-trading
|
|
|
|
|
|
|
|
|
Commodity
|
Notional
|
|
December 31, 2014
|
|
December 31, 2013
|
Natural Gas
|
MMBtu
|
|
9,690
|
|
|
3,513
|
|
Natural Gas Basis
|
MMBtu
|
|
2,710
|
|
|
373
|
|
Electricity
|
MWh
|
|
607
|
|
|
465
|
|
Trading
|
|
|
|
|
|
|
|
|
Commodity
|
Notional
|
|
December 31, 2014
|
|
December 31, 2013
|
Natural Gas
|
MMBtu
|
|
(155
|
)
|
|
2,259
|
|
Natural Gas Basis
|
MMBtu
|
|
(56
|
)
|
|
1,443
|
|
Gains (Losses) on Derivative Instruments
Gains (losses) on derivative instruments, net and current period settlements on derivative instruments were as follows for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
|
2012
|
Loss on non-trading derivatives—cash flow hedges, net (including ineffectiveness gain (loss) of ($288) and $930 for the years ended December 31, 2013 and 2012, respectively.)
|
$
|
—
|
|
|
$
|
84
|
|
|
$
|
(17,942
|
)
|
Gain (loss) on non-trading derivatives, net
|
(8,713
|
)
|
|
1,345
|
|
|
(1,074
|
)
|
Gain (loss) on trading derivatives, net (including gain on trading derivatives—affiliates, net of $203, $1,509 and $506 for the years ended December 31, 2014, 2013 and 2012, respectively)
|
(5,822
|
)
|
|
5,138
|
|
|
(2,469
|
)
|
Gain (loss) on derivatives, net
|
$
|
(14,535
|
)
|
|
$
|
6,567
|
|
|
$
|
(21,485
|
)
|
Current period settlements on non-trading derivatives—cash flow hedges
|
$
|
—
|
|
|
$
|
(1,180
|
)
|
|
$
|
18,707
|
|
Current period settlements on non-trading derivatives
|
(6,289
|
)
|
|
1,833
|
|
|
7,782
|
|
Current period settlements on trading derivatives (including current period settlements on trading derivatives—affiliates, net of $315, ($1,780) and $87 for the years ended December 31, 2014, 2013 and 2012, respectively)
|
2,810
|
|
|
387
|
|
|
312
|
|
Total current period settlements on derivatives
|
$
|
(3,479
|
)
|
|
$
|
1,040
|
|
|
$
|
26,801
|
|
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 revenues or retail cost of revenues on the combined and consolidated statements of operations.
Fair Value of Derivative Instruments
The following tables summarize the fair value and offsetting amounts of the Company’s derivative instruments by counterparty and collateral received or paid as of (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
Description
|
Gross Assets
|
|
Gross
Amounts
Offset
|
|
Net Assets
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
Non-trading commodity derivatives
|
$
|
3,642
|
|
|
$
|
(3,562
|
)
|
|
$
|
80
|
|
|
$
|
—
|
|
|
$
|
80
|
|
Trading commodity derivatives
|
234
|
|
|
(98
|
)
|
|
136
|
|
|
—
|
|
|
136
|
|
Total Current Derivative Assets
|
3,876
|
|
|
(3,660
|
)
|
|
216
|
|
|
—
|
|
|
216
|
|
Non-trading commodity derivatives
|
313
|
|
|
(313
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Non-current Derivative Assets
|
313
|
|
|
(313
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Derivative Assets
|
$
|
4,189
|
|
|
$
|
(3,973
|
)
|
|
$
|
216
|
|
|
$
|
—
|
|
|
$
|
216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
Description
|
Gross
Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Liabilities
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
Non-trading commodity derivatives
|
$
|
(14,911
|
)
|
|
$
|
3,562
|
|
|
$
|
(11,349
|
)
|
|
$
|
—
|
|
|
$
|
(11,349
|
)
|
Trading commodity derivatives
|
(275
|
)
|
|
98
|
|
|
(177
|
)
|
|
—
|
|
|
(177
|
)
|
Total Current Derivative Liabilities
|
(15,186
|
)
|
|
3,660
|
|
|
(11,526
|
)
|
|
—
|
|
|
(11,526
|
)
|
Non-trading commodity derivatives
|
(791
|
)
|
|
313
|
|
|
(478
|
)
|
|
—
|
|
|
(478
|
)
|
Total Non-current Derivative Liabilities
|
(791
|
)
|
|
313
|
|
|
(478
|
)
|
|
—
|
|
|
(478
|
)
|
Total Derivative Liabilities
|
$
|
(15,977
|
)
|
|
$
|
3,973
|
|
|
$
|
(12,004
|
)
|
|
$
|
—
|
|
|
$
|
(12,004
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
Description
|
Gross Assets
|
|
Gross
Amounts
Offset
|
|
Net Assets
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
Non-trading commodity derivatives
|
$
|
11,564
|
|
|
$
|
(6,898
|
)
|
|
$
|
4,666
|
|
|
$
|
—
|
|
|
$
|
4,666
|
|
Trading commodity derivatives
|
3,949
|
|
|
(544
|
)
|
|
3,405
|
|
|
—
|
|
|
3,405
|
|
Total Current Derivative Assets
|
15,513
|
|
|
(7,442
|
)
|
|
8,071
|
|
|
—
|
|
|
8,071
|
|
Non-trading commodity derivatives
|
100
|
|
|
(94
|
)
|
|
6
|
|
|
—
|
|
|
6
|
|
Trading commodity derivatives
|
14
|
|
|
(14
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Non-current Derivative Assets
|
114
|
|
|
(108
|
)
|
|
6
|
|
|
—
|
|
|
6
|
|
Total Derivative Assets
|
$
|
15,627
|
|
|
$
|
(7,550
|
)
|
|
$
|
8,077
|
|
|
$
|
—
|
|
|
$
|
8,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
Description
|
Gross
Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Liabilities
|
|
Cash
Collateral
Offset
|
|
Net Amount
Presented
|
Non-trading commodity derivatives
|
$
|
(8,289
|
)
|
|
$
|
6,898
|
|
|
$
|
(1,391
|
)
|
|
$
|
—
|
|
|
$
|
(1,391
|
)
|
Trading commodity derivatives
|
(986
|
)
|
|
544
|
|
|
(442
|
)
|
|
—
|
|
|
(442
|
)
|
Total Current Derivative Liabilities
|
(9,275
|
)
|
|
7,442
|
|
|
(1,833
|
)
|
|
—
|
|
|
(1,833
|
)
|
Non-trading commodity derivatives
|
(120
|
)
|
|
94
|
|
|
(26
|
)
|
|
—
|
|
|
(26
|
)
|
Trading commodity derivatives
|
(6
|
)
|
|
14
|
|
|
8
|
|
|
—
|
|
|
8
|
|
Total Non-current Derivative Liabilities
|
(126
|
)
|
|
108
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
Total Derivative Liabilities
|
$
|
(9,401
|
)
|
|
$
|
7,550
|
|
|
$
|
(1,851
|
)
|
|
$
|
—
|
|
|
$
|
(1,851
|
)
|
Accumulated Other Comprehensive Income
The following table summarizes the effects on the Company’s accumulated OCI balance attributable to cash flow hedge derivative instruments for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
Accumulated OCI balance, beginning of period
|
$
|
—
|
|
|
$
|
(2,536
|
)
|
Deferred gain (loss) on cash flow hedge derivative instruments
|
—
|
|
|
2,620
|
|
Reclassification of accumulated OCI net to income
|
—
|
|
|
(84
|
)
|
Accumulated OCI balance, end of period
|
$
|
—
|
|
|
$
|
—
|
|
The amounts reclassified from accumulated OCI into income and any amounts recognized in income from the ineffective portion of cash flow hedges are recorded in retail cost of revenues. In June 2013, the Company elected to discontinue cash flow hedge accounting.
7. Equity
Class A Common Stock
The Company has a total of
3,000,000
shares of its Class A common stock outstanding at December 31, 2014. Each share of Class A common stock holds economic rights and entitles its holder to
one
vote on all matters to be voted on by shareholders generally.
Class B Common Stock
The Company has a total of
10,750,000
shares of its Class B common stock outstanding at December 31, 2014. Each share of Class B common stock, all of which is held by NuDevco, has no economic rights but entitles its holder to
one
vote on all matters to be voted on by shareholders generally.
Holders of Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.
Preferred Stock
The Company has
20,000,000
shares of authorized preferred stock for which there are
no
issued and outstanding shares at December 31, 2014.
Earnings Per Share
The Company’s unvested restricted stock units were not recognized in dilutive earnings per share as they would have been antidilutive. The Class B common stock conversion to Class A common stock was not recognized in dilutive earnings per share for the year ended December 31, 2014 as the effect of the conversion would be antidilutive.
The following table presents the computation of earnings per share for the year ended December 31, 2014 (in thousands, except per share data):
|
|
|
|
|
|
Year Ended
|
|
December 31, 2014
|
Net loss attributable to Spark Energy, Inc. stockholders
|
$
|
(54
|
)
|
Basic weighted average Class A common shares outstanding
(1)
|
3,000
|
|
Basic EPS attributable to Spark Energy, Inc. stockholders
|
$
|
(0.02
|
)
|
|
|
Net loss attributable to Spark Energy, Inc. stockholders
|
$
|
(54
|
)
|
Effect of conversion of Class B common stock to shares of Class A common stock
|
—
|
|
Diluted net loss attributable to Spark Energy, Inc. stockholders
|
(54
|
)
|
Basic weighted average Class A common shares outstanding
(1)
|
3,000
|
|
Effect of dilutive Class B common stock
(1)
|
—
|
|
Effect of dilutive restricted stock units
|
—
|
|
Diluted weighted average shares outstanding
|
3,000
|
|
|
|
Diluted EPS attributable to Spark Energy, Inc. stockholders
|
$
|
(0.02
|
)
|
(1)
Based on outstanding shares for the period from the Offering date of August 1, 2014 to December 31, 2014.
8. Stock-Based Compensation
Restricted Stock Units
In connection with the Offering, the Company adopted the Spark Energy, Inc. Long-Term Incentive Plan (the “LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. The purpose of the LTIP is to provide a means to attract and retain individuals to serve as directors, employees and consultants who provide services to the Company by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of the Company’s Class A common stock. The LTIP provides for grants of cash payments, stock options, stock appreciation rights, restricted stock or units, bonus stock, dividend equivalents, and other stock-based awards with the total number of shares of stock available for issuance under the LTIP not to exceed
1,375,000
shares.
On August 1, 2014, the Company granted restricted stock units to our employees, non-employee directors and certain employees of our affiliates who perform services for the Company. The restricted stock unit awards vest over a
nine
month period for non-employee directors and ratably over approximately
three
or
four
years for officers, employees, and employees of affiliates, depending on years of service at the grant date, with the initial vesting date occurring on May 4, 2015 and each subsequent vesting date occurring each May 4 thereafter. Each restricted stock unit is entitled to receive a dividend equivalent when dividends are declared and distributed to shareholders of Class A common stock. These dividend equivalents shall be retained by the Company, reinvested in additional restricted stock units effective as of the record date of such dividends and vested upon the same schedule as the underlying restricted stock unit.
One
dividend was declared and paid during the year ended December 31, 2014, and the dividends associated with unvested restricted stock units resulted in additional restricted stock units issued. In accordance with ASC 718,
Compensation - Stock Compensation (“ASC 718”)
, the Company measures the cost of awards classified as equity awards based on the grant date fair value of the award, and the Company measures the cost of awards classified as liability awards at the fair value of the award at each reporting period. The Company has utilized an estimated
6%
annual forfeiture rate of restricted stock units in determining the fair value for all awards excluding those issued to executive level recipients and non-employee directors, for which no forfeitures are estimated to occur. The Company has elected to recognize related compensation expense on a straight-line basis over the associated vesting periods. Although the restricted stock units allow for cash settlement of the awards at the sole discretion of management of the Company, management intends to settle the awards by issuing shares of the Company’s Class A common stock.
Equity Classified Restricted Stock Units
Restricted stock units issued to employees and officers of the Company are classified as equity awards. The fair value of the equity classified restricted stock units was based on the Company’s Class A common stock price as of the grant date, and the Company recognized stock based compensation expense of
$0.5 million
for the year ended December 31, 2014 in general and administrative expense with a corresponding increase to additional paid in capital. No compensation expense was recorded for the same periods in 2013 and 2012 as there were no LTIP awards outstanding.
The following table summarizes equity classified restricted stock unit activity and unvested restricted stock units for the year ended December 31, 2014:
|
|
|
|
|
|
|
|
Number of Shares
|
Weighted Average Grant Date Fair Value
|
Unvested at December 31, 2013
|
—
|
|
—
|
|
Granted
|
264,150
|
|
$
|
18.00
|
|
Dividend reinvestment issuances
|
4,334
|
|
14.01
|
|
Vested
|
—
|
|
—
|
|
Forfeited
|
(11,600
|
)
|
18.00
|
|
Unvested at December 31, 2014
|
256,884
|
|
$
|
17.93
|
|
As of December 31, 2014, there was
$4.1 million
of total unrecognized compensation cost related to the Company’s equity classified restricted stock units, which is expected to be recognized over a weighted average period of approximately
3.2
years.
Liability Classified Restricted Stock Units
Restricted stock units issued to non-employee directors of the Company and employees of certain of our affiliates are classified as liability awards in accordance with ASC 718 as the awards are either to a) non-employee directors that allow for the recipient to choose net settlement for the amount of withholding taxes dues upon vesting or b) to employees of certain affiliates of the Company and are therefore not deemed to be employees of the Company. The fair value of the liability classified restricted stock units was based on the Company’s Class A common stock price as of the reported period ending date, and the Company recognized stock based compensation expense of
$0.3 million
for year ended December 31, 2014 in general and administrative expense with a corresponding increase to liabilities. As of December 31, 2014, the Company’s liabilities related to these restricted stock units recorded in other current liabilities and other non-current liabilities was
$0.1 million
and
$0.2 million
, respectively. No compensation expense was recorded for the same periods in 2013 and 2012 as there were no LTIP awards outstanding.
The following table summarizes liability classified restricted stock unit activity and unvested restricted stock units for the year ended December 31, 2014:
|
|
|
|
|
|
|
|
Number of Shares
|
Weighted Average Reporting Date Fair Value
|
Unvested at December 31, 2013
|
—
|
|
—
|
|
Granted
|
122,000
|
|
$
|
14.09
|
|
Dividend reinvestment issuances
|
2,093
|
|
14.09
|
|
Vested
|
—
|
|
—
|
|
Forfeited
|
—
|
|
—
|
|
Unvested at December 31, 2014
|
124,093
|
|
$
|
14.09
|
|
As of December 31, 2014, there was
$1.4 million
of total unrecognized compensation cost related to the Company’s liability classified restricted stock units, which is expected to be recognized over a weighted average period of approximately
2.2
years.
9. Income Taxes
The Company is subject to U.S. federal income tax as a corporation. Spark HoldCo and its subsidiaries are treated as flow-through entities for U.S. federal income tax purposes, and as such, are generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to their taxable income is passed through to their members or partners. Accordingly, the Company is subject to U.S. federal income taxation on its allocable share of Spark Holdco’s net U.S. taxable income.
The (benefit) provision for income taxes included the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
Current:
|
|
|
|
|
|
|
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
|
173
|
|
|
56
|
|
|
46
|
|
Total Current
|
|
173
|
|
|
56
|
|
|
46
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
Federal
|
|
(957
|
)
|
|
—
|
|
|
—
|
|
State
|
|
(107
|
)
|
|
—
|
|
|
—
|
|
Total Deferred
|
|
(1,064
|
)
|
|
—
|
|
|
—
|
|
(Benefit) provision for income taxes
|
|
$
|
(891
|
)
|
|
$
|
56
|
|
|
$
|
46
|
|
For the year ended December 31, 2013 and 2012, income taxes relate solely to the Company’s Texas franchise tax liability, which is computed on a modified gross margin. The Company does not do business in any other state where a similar tax is applied.
The effective income tax rate was
17.3%
for the year ended December 31, 2014. The following table reconciles the income tax benefit included in the combined and consolidated statement of operations with income tax expense that would result from application of the statutory federal tax rate,
34%
, to loss before income tax expense:
|
|
|
|
|
|
(in thousands)
|
|
2014
|
Expected benefit at federal statutory rate
|
|
$
|
(1,753
|
)
|
Increase (decrease) resulting from:
|
|
|
Noncontrolling interest
|
|
1,451
|
|
Corporate costs
|
|
(607
|
)
|
State income taxes, net of federal income tax effect
|
|
69
|
|
Other
|
|
(51
|
)
|
Benefit for income taxes
|
|
$
|
(891
|
)
|
For the year ended December 31, 2013 and 2012, the rate reconciliation calculation is not applicable as the Company was not subject to federal income taxes prior to the Offering.
The Company accounts for income taxes using the assets and liabilities method. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and those assets and liabilities tax bases. The Company applies existing tax law and the tax rate that the Company expects to apply to taxable income in the years in which those differences are expected to be recovered or settled in calculating the deferred tax assets and liabilities. Effects of changes in tax rates on deferred tax assets and liabilities are recognized in income in the period of the tax rate enactment. A valuation allowance is recorded when it is not more likely than not that some or all of the benefit from the deferred tax asset will be realized.
The components of the Company’s deferred tax assets as of December 31, 2014 are as follows:
|
|
|
|
|
|
(in thousands)
|
|
2014
|
Current deferred tax assets:
|
|
|
Net operating loss carryforward
|
|
$
|
654
|
|
Non-current deferred tax assets:
|
|
|
Investment in Spark HoldCo
|
|
16,171
|
|
Benefit of TRA liability
|
|
7,817
|
|
Net operating loss carryforward
|
|
59
|
|
Total non-current deferred tax assets
|
|
24,047
|
|
Total deferred tax assets
|
|
$
|
24,701
|
|
Current deferred tax assets are recorded in other current assets in the combined and consolidated financial statements. The Company had no material deferred tax assets or liabilities as of December 31, 2013 and 2012.
On the Offering date, the Company recorded a net deferred tax asset related to the step up in tax basis resulting from the purchase by the Company of Spark HoldCo units from NuDevco. In addition, the Company recorded a long-term liability to record the effect of the Tax Receivable Agreement liability (See Note 11 “Transactions with Affiliates” for further discussion) and a corresponding long-term deferred tax asset. The payable pursuant to the Tax Receivable Agreement and the deferred tax assets were recorded with a corresponding offset to additional paid-in capital.
The Company has a federal net operating loss carry forward totaling
$1.9 million
expiring in 2034 and a state net operating loss of
$1.8 million
expiring through 2034. No valuation allowance has been recorded as management believes that there will be sufficient future taxable income to fully utilize deferred tax assets.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. The Company believes it is more likely than not that the deferred tax assets will be utilized.
Separate federal and state income tax returns are filed for Spark Energy, Inc. and Spark HoldCo. The tax years 2010 through 2013 remain open to examination by the major taxing jurisdictions to which the Company is subject to income tax. NuDevco would be responsible for any audit adjustments incurred in connection with transactions occurring up to July 31, 2014. The last closed audit period of exam was for the 2011 Spark Energy, LLC’s federal tax return and resulted in no adjustments by the IRS. The Company is not currently under any income tax audits.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2014, 2013 and 2012 there was
no
liability or expense recorded for interest and penalties associated with uncertain tax positions or unrecognized tax positions. Additionally, the Company does not have unrecognized tax benefits as of December 31, 2014, 2013 and 2012.
10. Commitments and Contingencies
From time to time, the Company may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Management does not believe that we are a party to any litigation, claims or proceedings that will have a material impact on the Company’s combined and consolidated financial condition or results of operations.
11. Transactions with Affiliates
The Company enters into transactions with and pays certain costs on behalf of affiliates that are commonly controlled in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. The Company also sells and purchases natural gas and electricity with affiliates. The Company presents receivables and payables with the same affiliate on a net basis in the combined and consolidated balance sheets as all affiliate activity is with parties under common control.
Accounts Receivable and Payable-Affiliates
The Company recorded current accounts receivable-affiliates of
$1.2 million
and
$6.8 million
as of
December 31, 2014
and
2013
, respectively, and current accounts payable-affiliates of
$1.0 million
as of
December 31, 2014
for certain direct billings and cost allocations for services the Company provided to affiliates and sales or purchases of natural gas and electricity with affiliates.
Revenues and Cost of Revenues-Affiliates
Prior to Marlin’s initial public offering on July 31, 2013, the Company provided natural gas to Marlin, who is a processing service provider, whereby Marlin gathered natural gas from the Company and other third parties, extracted NGLs, and redelivered the processed natural gas to the Company and other third parties. Marlin replaced energy used in processing due to the extraction of liquids, compression and transportation of natural gas, and fuel by making a payment to the Company at market prices. Revenues-affiliates, recorded in net asset optimization revenues in the combined and consolidated statements of operations, related to Marlin’s payments to the Company for replaced energy for the years ended
December 31,
2013
and 2012 were
$
3.0 million
and
$8.3 million
, respectively.
Beginning on August 1, 2013, the Marlin processing agreement was terminated and the Company and another affiliate entered into an agreement whereby the Company purchased natural gas from the affiliate at the tailgate of the Marlin plant. Cost of revenues-affiliates, recorded in net asset optimization revenues in the combined and consolidated statements of operations for the years ended
December 31,
2014
and
2013
related to this agreement were
$30.3 million
and
$17.7 million
, respectively.
The Company also purchased natural gas at a nearby third party plant inlet which was then sold to the affiliate. Revenues-affiliates, recorded in net asset optimization revenues in the combined and consolidated statements of operations for the years ended
December 31,
2014
and
2013
related to these sales were
$12.8 million
and
$11.9 million
, respectively. There was
no
such activity in 2012.
Additionally, the Company entered into a natural gas transportation agreement with Marlin, at Marlin’s pipeline, whereby the Company transports retail natural gas and pays the higher of (i) a minimum monthly payment or (ii) a transportation fee per MMBtu times actual volumes transported. The current transportation agreement was set to expire on February 28, 2013, but was extended for
three
additional years at a fixed rate per MMBtu without a minimum monthly payment. Included in the Company’s results are cost of revenues-affiliates, recorded in retail cost of revenues in the combined and consolidated statements of operations related to this activity, which was less than
$0.1 million
,
$0.1 million
and
$0.3 million
for the years ended
December 31,
2014
,
2013
and 2012, respectively.
Prior to the Offering, the Company also purchased electricity for an affiliate and sold the electricity to the affiliate at the same market price that the Company paid to purchase the electricity. Sales of electricity to the affiliate were
$2.2 million
,
$4.0 million
and
$1.4 million
for the years ended
December 31,
2014
,
2013
and 2012, respectively, which is recorded in retail revenues-affiliate in the combined and consolidated statements of operations.
Also included in the Company’s results are cost of revenues-affiliates related to derivative instruments, recorded in net asset optimization revenues in the combined and consolidated statements of operations, is a loss of
$0.6 million
,
a gain of
$1.8 million
and a loss of
$0.6 million
for the years ended
December 31,
2014
,
2013
and 2012, respectively.
Cost Allocations
The Company paid certain expenses on behalf of affiliates, which are reimbursed by the affiliates to the Company, including costs that can be specifically identified and certain allocated overhead costs associated with general and administrative services, including executive management, facilities, banking arrangements, professional fees, insurance, information services, human resources and other support departments to the affiliates. Where costs incurred on behalf of the affiliate could not be determined by specific identification for direct billing, the costs were primarily allocated to the affiliated entities based on percentage of departmental usage, wages or headcount. The total amount direct billed and allocated to affiliates was
$5.1 million
,
$7.4 million
and
$4.1 million
for the years ended
December 31,
2014
,
2013
and 2012, respectively, which is recorded as a reduction in general and administrative expenses in the combined and consolidated statements of operations.
The Company pays residual commissions to an affiliate for all customers enrolled by the affiliate who pay their monthly retail gas or retail electricity bill. Commissions paid to the affiliate was less than
$0.1 million
for the years ended
December 31,
2014
and
2013
, respectively, and
$0.8 million
for the year ended December 31, 2012, which is recorded in general and administrative expense in the combined and consolidated statements of operations. This agreement with the affiliate was terminated in May 2014.
Member Distributions and Contributions
During the years ended
December 31,
2014
,
2013
and 2012, the Company made net capital distributions to W. Keith Maxwell III of
$36.4 million
,
$59.3 million
and
$10.4 million
, respectively. In contemplation of the Company’s initial public offering, the Company entered into an agreement with an affiliate in April 2014 to permanently forgive all net outstanding accounts receivable balances from the affiliate through the Offering date. As such, the accounts receivable balances from the affiliate have been eliminated and presented as a distribution to W. Keith Maxwell III for
2014
,
2013
and 2012.
Property and Equipment Sold
In 2012, the Company sold a field office facility, vehicles and computer and other equipment to affiliates for
$0.6 million
. The assets were sold at the Company’s historical cost basis at the time of the sale, as the transactions were between affiliates under common control.
Tax Receivable Agreement
Concurrently with the closing of the Offering, the Company entered into a Tax Receivable Agreement with Spark HoldCo, NuDevco Retail Holdings and NuDevco Retail. This agreement generally provides for the payment by the Company to NuDevco of
85%
of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the purchase by the Company of Spark HoldCo units from NuDevco Retail Holdings in connection with the Offering, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. The Company retains the benefit of the remaining
15%
of these tax savings. See Note 9 “Taxes” for further discussion of amounts recorded in connection with the Offering.
In certain circumstances, the Company may defer or partially defer any payment due (a “TRA Payment”) to the holders of rights under the Tax Receivable Agreement, which are currently NuDevco Retail Holdings and NuDevco
Retail. No TRA Payment was made during 2014, and any future TRA Payments due with respect to a given taxable year are expected to be paid in December of the subsequent calendar year.
During the
five
-year period commencing October 1, 2014, the Company will defer all or a portion of any TRA Payment owed pursuant to the Tax Receivable Agreement to the extent that Spark HoldCo does not generate sufficient Cash Available for Distribution (as defined below) during the four-quarter period ending September 30th of the applicable year in which the TRA Payment is to be made in an amount that equals or exceeds
130%
(the “TRA Coverage Ratio”) of the Total Distributions (as defined below) paid in such four-quarter period by Spark HoldCo. For purposes of computing the TRA Coverage Ratio:
|
|
•
|
“Cash Available for Distribution” is generally defined as the Adjusted EBITDA of Spark HoldCo for the applicable period, less (i) cash interest paid by Spark HoldCo, (ii) capital expenditures of Spark HoldCo (exclusive of customer acquisition costs) and (iii) any taxes payable by Spark HoldCo; and
|
|
|
•
|
“Total Distributions” are defined as the aggregate distributions necessary to cause the Company to receive distributions of cash equal to (i) the targeted quarterly distribution the Company intends to pay to holders of its Class A common stock payable during the applicable four-quarter period, plus (ii) the estimated taxes payable by the Company during such four-quarter period, plus (iii) the expected TRA Payment payable during the calendar year for which the TRA Coverage Ratio is being tested.
|
In the event that the TRA Coverage Ratio is not satisfied in any calendar year, the Company will defer all or a portion of the TRA Payment to NuDevco under the Tax Receivable Agreement to the extent necessary to permit Spark HoldCo to satisfy the TRA Coverage Ratio (and Spark HoldCo is not required to make and will not make the pro rata distributions to its members with respect to the deferred portion of the TRA Payment). If the TRA Coverage Ratio is satisfied in any calendar year, the Company will pay NuDevco the full amount of the TRA Payment.
Following the
five
-year deferral period, the Company will be obligated to pay any outstanding deferred TRA Payments to the extent such deferred TRA Payments do not exceed (i) the lesser of the Company’s proportionate share of aggregate Cash Available for Distribution of Spark HoldCo during the five-year deferral period or the cash distributions actually received by the Company during the
five
-year deferral period, reduced by (ii) the sum of (a) the aggregate target quarterly dividends (which, for the purposes of the Tax Receivable Agreement, will be
$0.3625
per share per quarter) during the five-year deferral period, (b) the Company’s estimated taxes during the five-year deferral period, and (c) all prior TRA Payments and (y) if with respect to the quarterly period during which the deferred TRA Payment is otherwise paid or payable, Spark HoldCo has or reasonably determines it will have amounts necessary to cause the Company to receive distributions of cash equal to the target quarterly distribution payable during that quarterly period. Any portion of the deferred TRA Payments not payable due to these limitations will no longer be payable.
12. Segment Reporting
The Company’s determination of reportable business segments considers the strategic operating units under which the Company makes financial decisions, allocates resources and assesses performance of its retail and asset optimization businesses.
The Company’s reportable business segments are retail natural gas and retail electricity. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Asset optimization activities, considered an integral part of securing the lowest price natural gas to serve retail gas load, are part of the retail natural gas segment. The Company recorded asset optimization revenues of
$284.6 million
,
$192.4 million
and
$248.6 million
and asset optimization cost of revenues of
$282.3 million
,
$192.1 million
and
$249.7 million
for the
years ended
December 31,
2014
,
2013
and 2012, respectively, which are presented on a net basis in asset optimization revenues. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. Corporate and other consists of expenses and assets of the retail natural gas and retail electricity segments that are managed at a consolidated level such as general and administrative expenses.
To assess the performance of the Company’s operating segments, the chief operating decision maker analyzes retail gross margin. The Company defines retail gross margin as operating income plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (i) net asset optimization revenues, (ii) net gains (losses) on non-trading derivative instruments, and (iii) net current period cash settlements on non-trading derivative instruments. The Company deducts net gains (losses) on non-trading derivative instruments, excluding current period cash settlements, from the retail gross margin calculation in order to remove the non-cash impact of net gains and losses on non-trading derivative instruments.
Retail gross margin is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity business by removing the impacts of our asset optimization activities and net non-cash income (loss) impact of our economic hedging activities. As an indicator of our retail energy business’ operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income, as determined in accordance with GAAP. Below is a reconciliation of retail gross margin to (loss) income before income tax expense.
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Years Ended December 31,
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(in thousands)
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|
2014
|
|
2013
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|
2012
|
Reconciliation of Retail Gross Margin to (Loss)income before taxes
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|
|
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(Loss) income before income tax expense
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|
$
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(5,156
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)
|
|
$
|
31,468
|
|
|
$
|
26,139
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|
Interest and other income
|
|
(263
|
)
|
|
(353
|
)
|
|
(62
|
)
|
Interest expense
|
|
1,578
|
|
|
1,714
|
|
|
3,363
|
|
Operating Income
|
|
(3,841
|
)
|
|
32,829
|
|
|
29,440
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|
Depreciation and amortization
|
|
22,221
|
|
|
16,215
|
|
|
22,795
|
|
General and administrative
|
|
45,880
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|
|
35,020
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|
47,321
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Less:
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Net asset optimization revenue
|
|
2,318
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|
|
314
|
|
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(1,136
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)
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Net, Gains (losses) on non-trading derivative instruments
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|
(8,713
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)
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|
1,429
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(19,016
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)
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Net, Cash settlements on non-trading derivative instruments
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(6,289
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)
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|
653
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26,489
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Retail Gross Margin
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$
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76,944
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$
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81,668
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$
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93,219
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The Company uses retail gross margin and net asset optimization revenues as the measure of profit or loss for its business segments. This measure represents the lowest level of information that is provided to the chief operating decision maker for our reportable segments.
Financial data for business segments are as follows (in thousands):
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Year Ended December 31, 2014
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Retail
Electricity
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Retail
Natural Gas
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Corporate
and Other
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Eliminations
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Total Spark Retail
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Total Revenues
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$
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176,406
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$
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146,470
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$
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—
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$
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—
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$
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322,876
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Retail cost of revenues
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149,452
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|
109,164
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—
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—
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258,616
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Less:
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Net asset optimization revenues
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—
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2,318
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—
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—
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2,318
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Net, Gains (losses) on non-trading derivative instruments
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(518
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)
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(8,195
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)
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—
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—
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(8,713
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)
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Current period settlements on non-trading derivatives
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(5,145
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)
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(1,144
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)
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—
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—
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(6,289
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)
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Retail gross margin
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$
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32,617
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|
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$
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44,327
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$
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—
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$
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—
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$
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76,944
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Total Assets
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$
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46,848
|
|
|
$
|
101,711
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|
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$
|
27,285
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|
|
$
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(37,447
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)
|
|
$
|
138,397
|
|
|
|
|
|
|
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Year Ended December 31, 2013
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Retail
Electricity
|
|
Retail
Natural Gas
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Corporate
and Other
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Eliminations
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Total Spark Retail
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Total Revenues
|
$
|
191,872
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|
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$
|
125,218
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$
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—
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|
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$
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—
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$
|
317,090
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Retail cost of revenues
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149,885
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|
83,141
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|
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—
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—
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233,026
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Less:
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Net asset optimization revenues
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—
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|
|
314
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|
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—
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—
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314
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Net, Gains (losses) on non-trading derivative instruments
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1,336
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|
93
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|
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—
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—
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1,429
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Current period settlements on non-trading derivatives
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1,349
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(696
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)
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—
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—
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|
653
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|
Retail gross margin
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$
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39,302
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|
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$
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42,366
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$
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—
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|
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$
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—
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$
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81,668
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Total Assets
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$
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41,879
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|
|
$
|
87,985
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|
|
$
|
953
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|
$
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(21,744
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)
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|
$
|
109,073
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Year Ended December 31, 2012
|
Retail
Electricity
|
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Retail
Natural Gas
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Corporate
and Other
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Eliminations
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|
Spark Retail
|
Total Revenues
|
$
|
256,357
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$
|
122,705
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$
|
—
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$
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—
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$
|
379,062
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Retail cost of revenues
|
202,440
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|
77,066
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—
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—
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|
279,506
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Less:
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|
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Net asset optimization revenues
|
—
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|
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(1,136
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)
|
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—
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|
|
—
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|
|
(1,136
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)
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Net, Gains (losses) on non-trading derivative instruments
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(17,400
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)
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(1,616
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)
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—
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—
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$
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(19,016
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)
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Current period settlements on non-trading derivatives
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18,577
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|
7,912
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—
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—
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26,489
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Retail gross margin
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$
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52,740
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|
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$
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40,479
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|
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$
|
—
|
|
|
$
|
—
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|
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$
|
93,219
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Significant Customers
For the years ended
December 31, 2014
, 2013 and 2012, we had
one
significant customer that individually accounted for more than
10%
of the Company’s combined and consolidated net asset optimization revenues.
Significant Suppliers
For the years ended
December 31, 2014
, 2013 and 2012, we had
one
significant supplier that individually accounted for more than
10%
of the Company’s combined and consolidated net asset optimization revenues cost of revenues.
For the years ended
December 31, 2014
, and 2013, the Company had
three
and
one
significant suppliers that individually accounted for more than
10%
of the Company’s combined and consolidated retail electricity retail cost of revenues, respectively. There were
no
significant suppliers for retail electricity in 2012.
13. Customer Acquisitions
During the fourth quarter of 2014, the Company entered into
two
purchase and sale agreements for the purchase of approximately
13,400
variable rate electricity contracts in Connecticut for a purchase price of approximately
$2.2 million
. The purchase prices are capitalized as intangible assets - customer acquisitions to be amortized over a
three
year period as customers begin using electricity under a contract with the Company. As of December 31, 2014 the Company had paid and capitalized approximately
$1.5 million
related to these purchases.
14. Subsequent Events
On February 16, 2015, the Company declared a dividend of
$0.3625
per share to holders of record of our Class A common stock on March 2, 2015 which was paid on March 16, 2015.
On March 3, 2015, the Company entered into a purchase and sale agreement for the purchase of approximately
33,500
residential and commercial natural gas contracts in Northern California for a purchase price of approximately
$2.8 million
, depending on the number of contracts that come on flow. The transaction is expected to close in April 2015 subject to certain closing conditions.
Supplemental Quarterly Financial Data (unaudited)
Summarized unaudited quarterly financial data is as follows:
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|
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Quarter Ended
|
|
2014
|
|
December 31
|
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September 30
|
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June 30
|
|
March 31
|
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(In thousands, except per share data)
|
Total Revenues
|
$
|
82,742
|
|
|
$
|
68,217
|
|
|
$
|
65,941
|
|
|
$
|
105,976
|
|
Operating (loss) income
|
(12,786
|
)
|
|
1,607
|
|
|
555
|
|
|
6,783
|
|
Net (loss) income
|
(11,394
|
)
|
|
419
|
|
|
201
|
|
|
6,509
|
|
Net (loss) income attributable to Spark Energy, Inc. stockholders
|
(1,115
|
)
|
|
1,061
|
|
|
—
|
|
|
—
|
|
Net (loss) income attributable to Spark Energy, Inc. per common share - basic
|
(0.37
|
)
|
|
0.35
|
|
|
N/A*
|
|
|
N/A*
|
|
Net (loss) income attributable to Spark Energy, Inc. per common share - diluted
|
(0.37
|
)
|
|
0.03
|
|
|
N/A*
|
|
|
N/A*
|
|
*Per share data is not meaningful prior to the Company's initial public offering, effective August 1, 2014, as the Company operated under a sole-member ownership structure.
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|
|
|
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|
|
Quarter Ended
|
|
2013
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
|
(In thousands, except per share data)
|
Total Revenues
|
$
|
82,414
|
|
|
$
|
69,899
|
|
|
$
|
65,481
|
|
|
$
|
99,296
|
|
Operating income (loss)
|
19,587
|
|
|
(1,110
|
)
|
|
(646
|
)
|
|
14,998
|
|
Net income (loss)
|
19,344
|
|
|
(1,597
|
)
|
|
(946
|
)
|
|
14,611
|
|
Net income (loss) attributable to Spark Energy, Inc. stockholders
|
19,344
|
|
|
(1,597
|
)
|
|
(946
|
)
|
|
14,611
|
|
Net income attributable to Spark Energy, Inc. per common share - basic
|
N/A*
|
|
|
N/A*
|
|
|
N/A*
|
|
|
N/A*
|
|
Net income attributable to Spark Energy, Inc. per common share - diluted
|
N/A*
|
|
|
N/A*
|
|
|
N/A*
|
|
|
N/A*
|
|
*Per share data is not meaningful prior to the Company's initial public offering, effective August 1, 2014, as the Company operated under a sole-member ownership structure.
|