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EX-31.1 - CHIEF EXECUTIVE OFFICER CERTIFICATION - ASPIRITY HOLDINGS LLCaspirity_10q-ex3101.htm
EX-32.1 - CERTIFICATION - ASPIRITY HOLDINGS LLCaspirity_10q-ex3201.htm
EX-31.2 - CHIEF FINANCIAL OFFICER CERTIFICATION - ASPIRITY HOLDINGS LLCaspirity_10q-ex3102.htm

UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-Q

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2015

 

or

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from _________ to _________

 

 

Commission File Number: 333-203994

 

Aspirity Holdings LLC

(Exact name of registrant as specified in its charter)

 

Minnesota   6221 – Commodity Contracts Brokers and Dealers   27-1658449
(State of organization)   (Primary Standard Industrial Classification Code Number)   (IRS Employer Identification Number)
         
 

701 Xenia Avenue South, Suite 475

Minneapolis, MN 55416

 
  (Address of principal executive offices, zip code)  
     
  (763) 432-1500  
  (Registrant’s telephone number, including area code)  
     
 

Twin Cities Power Holdings, LLC

16233 Kenyon Avenue, Suite 210

Lakeville, Minnesota 55044

 
  (Former name, former address and former fiscal year, if changed since last report)  
             

 

_________________________________________________________

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒    No ☐

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒    No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or smaller reporting company. See definition of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer ☐ Accelerated filer ☐   Non-accelerated filer ☐   Smaller reporting company  ☒

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐   No ☒

 

   
 

 

TABLE OF CONTENTS

 

Definitions 2
   
Forward Looking Statements 8
   
Non-GAAP Financial Measures 9
   
Part I – Financial Information 10
   
Item 1 - Financial Statements (Unaudited) 10
Consolidated Balance Sheets 10
As of September 30, 2015 and December 31, 2014 10
Consolidated Statements of Comprehensive Income 11
Three and Nine Months ended September 30, 2015 and 2014 11
Consolidated Statements of Cash Flows 12
Nine Months Ended September 30, 2015 and 2014 12
Notes to Consolidated Financial Statements 14
   
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations 49
Industry Background 49
Company Overview 54
The Restructuring 54
Summary Pro Forma Financial Information 58
Business Plans 60
Operations Prior to the Distribution 60
Results of Operations 63
Three Months Ended September 30, 2015 and 2014 63
Nine Months Ended September 30, 2015 and 2014 69
Liquidity, Capital Resources, and Cash Flow 73
Financing 75
Non-GAAP Financial Measures 77
Critical Accounting Policies and Estimates 78
   
Item 3 - Quantitative and Qualitative Disclosures about Market Risk 80
Commodity Price Risk 80
Interest Rate Risk 81
Liquidity Risk 82
Wholesale Counterparty Credit Risk 82
Retail Customer Credit Risk 82
Foreign Exchange Risk 82
   
Item 4 - Controls and Procedures 83
   
Part II – Other Information 84
Item 1 - Legal Proceedings 84
Item 1A - Risk Factors 84
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds 84
Item 3 - Defaults Upon Senior Securities 84
Item 4 - Mine Safety Disclosures 84
Item 5 - Other Information 84
Item 6 - Exhibits 85
   
Signatures 87

 

 i 
 

 

Definitions

 

Abbreviation or acronym   Definition
ABN AMRO   ABN AMRO Clearing Chicago, LLC and ABN AMRO Clearing Bank, N.V.
AENE   Aspirity Energy Northeast LLC, a wholly owned subsidiary of Aspirity Energy and a second tier subsidiary of the Company
AEMS   Aspirity Energy Mid-States LLC, a wholly owned subsidiary of Aspirity Energy and a second tier subsidiary of the Company
AESO   Alberta Electric System Operator, a statutory corporation of the Province of Alberta, is an ISO serving the Alberta Interconnected Electric System
AES   Aspirity Energy South LLC, a wholly owned subsidiary of Aspirity Energy and a second tier subsidiary of the Company
Angell   Angell Energy, LLC, a Texas limited liability company that purchased TCP and SUM from the Company on June 1, 2015
AOCI   Accumulated other comprehensive income
Apollo   Apollo Energy Services, LLC, a wholly-owned subsidiary of Enterprises and a second tier subsidiary of the Company
ASC   Accounting Standards Codification
Aspirity or the Company   Aspirity Holdings LLC and subsidiaries, formerly known as Twin Cities Power Holdings, LLC or “TCPH”
Aspirity Energy   Aspirity Energy LLC, a wholly owned subsidiary of the Company
Aspirity Financial   Aspirity Financial LLC, a wholly owned subsidiary of the Company
ASU   Accounting Standards Update
BLS   Bureau of Labor Statistics, an agency within the U.S. Department of Labor
Btu; therm; MMBtu   A “Btu” or British thermal unit is a measure of thermal energy or the amount of heat needed to raise the temperature of one pound of water from 39°F to 40°F. A “therm” is 100,000 Btu and a “MMBtu” is 1,000,000 Btu.
C$   Canadian dollars
CEF   Cygnus Energy Futures, LLC, a wholly-owned subsidiary of CP and a third tier subsidiary of the Company
CFTC   Commodity Futures Trading Commission, an independent agency of the United States government that regulates futures and option markets
CME   CME Group Inc. operates the CME (Chicago Mercantile Exchange), CBOT (Chicago Board of Trade), NYMEX (New York Mercantile Exchange), and COMEX (Commodities Exchange) derivatives exchanges and also offers certain cleared OTC products and services

 

 2 
 

 

Abbreviation or acronym   Definition
CoV   Abbreviates the coefficient of variation, a simple measure of volatility useful for comparing two or more data series; equal to the standard deviation divided by the mean
CP   Cygnus Partners, LLC, a wholly-owned subsidiary of Enterprises and second tier subsidiary of the Company
CP&U   Community Power & Utility, LLC, an electricity retailer acquired by TCP on June 29, 2012
CSE   Comparison shopping engine, a web site that compares prices for specific products. While most comparison shopping engines do not offer the products or services themselves, some may earn commissions when users follow the links in the search results and make a purchase from an online vendor
CTG   Chesapeake Trading Group, LLC, a wholly-owned subsidiary of Enterprises and a second tier subsidiary of the Company
Cyclone   Cyclone Partners, LLC, a wholly-owned subsidiary of Enterprises and a second tier subsidiary of the Company
Degree-days; CDD; HDD  

A “degree-day” compares outdoor temperatures to a standard of 65°F. Hot days require energy for cooling and are measured in cooling degree-days or “CDD” while cold days require energy for heating and are measured in heating degree-days or “HDD”. For example, a day with a mean temperature of 80°F would result in 15 CDD and a day with a mean temperature of 40°F would result in 25 HDD.

 

If heating degree-days are less than the average for an area for a period, the weather was “warmer than normal”; if they were greater, it was “colder than normal”. The converse is true for cooling degree-days - if CDD are less than the average for an area for a period, the weather was “colder than normal”; if they were greater, it was “warmer than normal”.

DOE   U.S. Department of Energy
EDC; LDC   Electric distribution company; may also be known as a local distribution company
EIA   Energy Information Administration, an independent agency within DOE
ERCOT   Electric Reliability Council of Texas, an ISO managing 85% of the electric Load of Texas and subject to oversight by the Public Utility Commission of Texas and the Texas Legislature but not FERC
FASB   Financial Accounting Standards Board
FERC   Federal Energy Regulatory Commission, an independent regulatory agency within DOE

 

 3 
 

 

Abbreviation or acronym   Definition
Form S-1   The Company’s Registration Statement on Form S-1, declared effective by the SEC on May 10, 2012 (the “Old S-1”) with respect to the Company’s Notes Offering, as replaced by its new registration statement, declared effective by the SEC on November 13, 2015 (the “New S-1”)
FTR   Financial Transmission Rights are financial instruments traded in certain ISOs and RTOs that entitle their holders to receive or pay charges based on congestion price differences in the day-ahead energy market across specific transmission paths. The value of an FTR reflects the difference in congestion prices rather than the difference in locational marginal prices, which includes energy, congestion, and marginal losses. FTRs are specified between any two pricing nodes on the system, including hubs, control zones, aggregates, generator buses, load buses and interface pricing points. FTRs are generally available in increments of 0.1 MW and for periods ranging from 1 month to multiple years. The value of an FTR can be positive or negative depending on the sink minus source congestion price difference, with a negative differences resulting in liability for the holder.
GAAP   Generally accepted accounting principles in the United States
ICE   InterContinental Exchange Group, Inc. operates a network of 17 regulated exchanges and 6 clearinghouses for financial and commodity markets in the U.S., Canada, Europe, and Asia. In November 2013, ICE completed the acquisition of NYSE Euronext.
INC and DEC   An increment offer or “INC” is an offer in the day-ahead market to sell energy at a specified source bus. An INC will clear if the LMP at the bus equals or exceeds the offer price. A decrement bid or “DEC” is a bid in the day-ahead market to purchase energy at a specified sink bus. A DEC will clear if the LMP at the bus does not exceed the bid price.
ISO; RTO   Independent System Operator, a non-profit organization formed at the direction or recommendation of FERC that coordinates, controls, and monitors the operation of a bulk electric power system, usually within a single U.S. state, but sometimes encompassing multiple states. A Regional Transmission Organization (“RTO”) typically performs the same functions as an ISO, but covers a larger area. ISOs and RTOs may also operate centrally cleared wholesale markets for electric power quoted on both a “real-time” and “day ahead” basis.
ISO-NE   ISO New England Inc., an RTO serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont
Enterprises   Krieger Enterprises, LLC, a wholly owned subsidiary of the Company

 

 4 
 

 

Abbreviation or acronym   Definition
LMP   One of the unique aspects of ISO electricity markets is the availability of “locational marginal prices” (“LMPs”). The theoretical price of electricity at each node on the network is calculated based on the assumptions that: (1) one additional megawatt-hour of energy is demanded at the node in question; and (2) the marginal cost to the system that would result from the re-dispatch of available generating units to serve such load can establish the production cost of the additional energy. LMPs are typically quoted on a “real-time” and “day-ahead” basis. In the real-time market, prices at specific nodes are updated every 5 minutes based on current and targeted supply and demand. Day-ahead prices are for power to be delivered at a specified hour and transmission point during the next day. LMPs vary by time and location due to physical system limitations, congestion, and loss factors; however, in an unconstrained system with no losses, all LMPs would be equal. This means that LMPs can be conceptually separated into three components - an energy price, a congestion component, and a loss component.
MCA   The Company’s Member Control Agreement, as amended
MEF   Minotaur Energy Futures, LLC, a wholly-owned subsidiary of TCP and a second-tier subsidiary of TCPH
MISO   Midcontinent Independent System Operator, Inc., (formerly the Midwest Independent Transmission System Operator, Inc.), an RTO serving all or part of Arkansas, Illinois, Indiana, Iowa, Louisiana, Manitoba, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, and Wisconsin
MCF   One thousand cubic feet, a common unit of price measure for natural gas. In 2010, one MCF of natural gas had a heat content of 1,025 Btu.
NERC   North American Electric Reliability Corporation, a non-profit corporation formed on March 28, 2006 as the successor to the National Electric Reliability Council, also known as NERC, formed in 1968. NERC is the designated Electric Reliability Organization (“ERO”) for the U.S. and operates under the auspices of FERC.
NGX   Natural Gas Exchange Inc., headquartered in Calgary, Alberta provides electronic trading, central counterparty clearing, and data services to the North American natural gas and electricity markets. NGX is wholly owned by TMX Group Inc. which collectively manages all aspects of Canada’s senior and junior equity markets.
NOAA   National Oceanic and Atmospheric Administration, an agency of the U.S. Department of Commerce
Noble   Noble Conservation Solutions, Inc., a Minnesota corporation. On  September 1, 2015, Enterprises purchased 60% of the outstanding shares of Noble.
Notes   The Company’s Renewable Unsecured Subordinated Notes issued pursuant to its ongoing Notes Offering
Notes Offering   The direct public offering the Company’s Notes

 

 5 
 

 

Abbreviation or acronym   Definition
NRSRO   A SEC-recognized Nationally Recognized Statistical Rating Organization; The major NRSROs that rate utilities are Standard & Poor’s Financial Services LLC (“S&P”), Moody’s Investor Services, Inc. (“Moody’s”), and Fitch Ratings Inc. (“Fitch”)
NYISO   New York Independent System Operator, an ISO serving New York state
OTC   Over-the-counter
PJM   PJM Interconnection, a RTO serving all or part of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.
POR; non-POR   All states with restructured retail markets have implemented laws and regulations with respect to permitted billing, credit, and collections practices. Some of these states require an EDC billing customers in their service territory on behalf of suppliers operating there to purchase the receivables generated as a result of energy sales, generally at a modest discount to reflect bad debt experience. These states are known as “purchase of receivables” or “POR” jurisdictions while those without this provision are known as “non-POR” areas.
PURPA   Public Utilities Regulatory Policy Act of 1978
RECs   Renewable energy certificates represent the property rights to the environmental, social, and other non-power qualities of renewable electricity generation and can be sold separately from the underlying physical electricity.
REH   Retail Energy Holdings, LLC, a wholly-owned subsidiary of Enterprises and a second tier subsidiary of the Company
SEC   U.S. Securities and Exchange Commission, an independent agency of the United States government with primary responsibility for enforcing federal securities laws and regulating the securities industry and stock exchanges
SUM   Summit Energy, LLC, a wholly-owned subsidiary of TCP
TCE   Twin Cities Energy, LLC, an inactive, wholly-owned subsidiary of Enterprises
TCP   Twin Cities Power, LLC
TCPC   Twin Cities Power – Canada, Ltd., an inactive, wholly-owned subsidiary of TCE
TSE   Town Square Energy, initially, an accounting division of TCP resulting from the acquisition of the business and assets of CP&U. Effective June 1, 2013, TSE became a wholly-owned subsidiary of the Company and on October 25, 2013, it became a wholly owned subsidiary of REH
TSEC   Town Square Energy Canada, Ltd, a wholly-owned subsidiary of REH
TSEE   Town Square Energy East, LLC, a wholly-owned subsidiary of REH, formerly known as Discount Energy Group, LLC or “DEG”

 

 6 
 

 

Abbreviation or acronym   Definition
UTC   In an up-to-congestion or “UTC” transaction, a day-ahead market participant offers to inject energy at a specified source and simultaneously withdraw the same quantity at a specific sink at a maximum bid price difference between the two locations. The transaction will clear if the price differential between sink and source does not exceed the bid price.
VaR   Value-at-Risk is a measure of the risk of loss on a specific portfolio of financial assets. For a given portfolio, probability, and time horizon, VaR is the value at which the probability that a mark-to-market loss over the given time horizon exceeds the calculated value, assuming normal markets and no trading. For example, if a portfolio has a one-day, 5% VaR of $1 million, there is a 5% probability that the portfolio will fall in value by more than $1 million over a one-day period.
Watt (W); Watt-hour (Wh)   Although in everyday usage, the terms “energy” and “power” are essentially synonyms, scientists, engineers, and the energy business distinguish between them. Technically, energy is the ability to do work, or move a mass a particular distance by the application of force while power is the rate at which energy is generated or consumed.  
     
    In the case of electricity, power is measured in watts (W) and is equal to voltage or the difference in charge between two points multiplied by amperage or the current or rate of electrical flow. The energy supplied or consumed by a circuit is measured in watt-hours (Wh). For example, when a light bulb with a power rating of 100W is turned on for one hour, the energy used is 100 watt-hours. This same amount of energy would light a 40-watt bulb for 2.5 hours or a 50-watt bulb for 2.0 hours.  
     
    Multiples of watts and watt-hours are measured using International Systems of Units (“SI”) conventions. For example:
     

    Prefix Symbol Multiple (Number) Value
    kilo k one thousand (1,000) 103
    mega M one million (1,000,000) 106
    giga G one billion (1,000,000,000) 109
    tera T one trillion (1,000,000,000,000) 1012

     
    Kilowatt (kW) or kilowatt-hour (kWh): one thousand watts or watt-hours. Kilowatt-hours are typically used to measure residential energy consumption and retail prices. One kWh is equal to 3,412 Btu, but fuel with a heat content of 7,000 to 11,500 Btu must be consumed to generate and deliver one kWh of electricity.  
     
    Megawatt (MW) or megawatt-hour (MWh): one million watts or watt-hours or one thousand kilowatts or kilowatt-hours. Megawatts are typically used to measure electrical generation capacity and megawatt-hours are the pricing units used in the wholesale electricity market.

 

 7 
 

 

Forward Looking Statements

 

Readers are urged to carefully review and consider the various disclosures made by us in this Form 10-Q and in our other reports filed with the SEC that attempt to advise interested parties of the factors that may affect our business.

 

Statements in this report that are not statements of historical facts may be considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. Any statements that express, or involve discussions as to, future expectations, risks, beliefs, plans, objectives, assumptions, events, uncertainties, financial performance, or growth strategies, often, but not always, through the use of words or phrases such as “anticipates”, “believes”, “estimates”, “expects”, “intends”, “plans”, “projects”, “likely”, “will continue”, “could”, “may”, “potential”, “target”, “outlook”, or words of similar meaning are not statements of historical facts and may be forward-looking.

 

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause our actual results to differ materially from those indicated in forward-looking statements made by or on behalf of the Company in this Form 10-Q, in presentations, on our website, in response to questions, or otherwise. You should not place undue reliance on any forward-looking statement. Examples of forward-looking statements include, among others, statements we make regarding:

 

·Expected operating results, such as revenue growth and earnings;
·Anticipated levels of capital expenditures and expansion of our retail electricity business segment;
·Current or future price volatility in the energy markets and future market conditions;
·Our belief that we have sufficient liquidity to fund our operations during the next 12 months;
·Expectations of the effect on our financial condition of claims, litigation, environmental costs, contingent liabilities, and governmental and regulatory investigations and proceedings;
·Our strategies for risk management; and
·Any other risk factors listed from time to time by the Company in reports filed with the Securities and Exchange Commission

 

Additional disclosures regarding factors that could cause our results and performance to differ from results or performance anticipated by this report are discussed under the heading “Item 1A – Risk Factors” of our Form 10-K for 2014 (the “2014 Form 10-K”), the “Risk Factors” section beginning on page 10 of our Form S-1, and any assumptions and other factors referred to specifically in connection with such forward-looking statements that could cause our actual results to differ materially from those indicated in the forward-looking statements.

 

Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can it assess the impact of each of these factors on the businesses of the Company or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

 

 8 
 

 

Non-GAAP Financial Measures

 

The Company’s communications may include certain non- GAAP financial measures. A “non-GAAP financial measure” is defined as a numerical measure of a company's financial performance, financial position, or cash flows that excludes, or includes, amounts that are included in, or excluded from, the most directly comparable measure calculated and presented in accordance with GAAP in the company's financial statements.

 

Non-GAAP financial measures utilized by the Company include “total liquid assets”. The most comparable GAAP measure is total current assets. The Company’s management believes that these non-GAAP financial measures provide useful information to investors and enable investors and analysts to more accurately compare the Company's ongoing financial performance over the periods presented.

 

 9 
 

Part I – Financial Information

 

Item 1 - Financial Statements (Unaudited)

 

Aspirity Holdings LLC and Subsidiaries

Consolidated Balance Sheets

As of September 30, 2015 and December 31, 2014

  

   September 30,   December 31, 
   2015   2014 
   Unaudited   Unaudited 
Assets          
Current assets          
Cash - unrestricted  $2,346,124   $2,397,300 
Cash in trading accounts   8,921,474    21,099,652 
Accounts receivable, net   6,210,753    2,394,246 
Costs and estimated earnings in excess of billings on uncompleted contracts   27,034     
Marketable securities   389,974    311,586 
Notes receivable, net of deferred gain   760,504     
Prepaid expenses and other current assets   327,256    416,419 
Total current assets   18,983,119    26,619,203 
           
Property, equipment, and furniture, net   1,144,578    762,529 
           
Other assets          
Intangible assets, net   469,261    269,149 
Deferred financing costs, net   380,142    241,744 
Cash - restricted   1,319,371    1,319,371 
Real estate held for development   2,387,079    953,462 
Notes receivable, net of deferred gain   2,545,412     
Investment in convertible note   1,718,631    1,604,879 
Goodwill   1,555,277     
Other assets   19,431     
Total assets  $30,522,301   $31,770,337 
           
Liabilities and Members' (Deficit) Equity          
           
Current liabilities          
Current portions of debt          
Revolver  $2,976,515   $1,105,259 
Senior notes   1,213,991    312,068 
Renewable unsecured subordinated notes   9,422,406    7,234,559 
Accounts payable - trade   4,245,272    1,544,103 
Accrued expenses   1,752,086    681,995 
Billings in excess of costs and estimated earnings on uncompleted contracts   466,500     
Accrued compensation   936,090    3,601,282 
Accrued interest   1,315,473    849,913 
Obligations under settlement agreement       582,565 
Total current liabilities   22,328,333    15,911,744 
           
Long-term liabilities          
Senior notes   248,376    217,451 
Renewable unsecured subordinated notes   13,257,693    10,418,569 
Obligations under settlement agreement       2,524,448 
Total long term liabilities   13,506,069    13,160,468 
Total liabilities   35,834,402    29,072,212 
           
Commitments and contingencies          
           
Members' (deficit) equity          
Series A preferred equity   2,745,000    2,745,000 
Common equity   (9,023,671)   (193,624)
Accumulated other comprehensive income   443,854    146,749 
Non-controlling interest   522,716     
Total members' (deficit) equity   (5,312,101)   2,698,125 
Total liabilities and members' (deficit) equity  $30,522,301   $31,770,337 

 

See notes to consolidated financial statements.

 10 
 

 

Aspirity Holdings LLC and Subsidiaries

Consolidated Statements of Comprehensive Income

Three and Nine Months ended September 30, 2015 and 2014

 

   Three Months   Nine Months 
   Ended September 30,   Ended September 30, 
   2015   2014   2015   2014 
   Unaudited   Unaudited   Unaudited   Unaudited 
Revenue                    
Wholesale trading, net  $1,309,120   $1,414,252   $13,081,327   $32,740,637 
Retail energy services   10,122,398    2,988,460    23,566,115    8,115,008 
Real estate sales   351,725        351,725     
Management services   375,000        500,000     
Construction services   714,506        714,506     
    12,872,749    4,402,712    38,213,673    40,855,645 
                     
Costs and expenses                    
Cost of retail electricity sold   8,031,489    2,629,531    20,350,365    8,896,838 
Cost of real estate sold   297,482        297,482     
Cost of construction services   620,426        620,426     
Retail energy sales and marketing   420,821    40,622    1,023,728    192,017 
Compensation and benefits   1,965,855    1,555,862    11,195,996    15,849,013 
Professional fees   818,259    988,698    2,134,759    2,116,884 
Other general and administrative   1,109,748    3,450,572    3,420,466    5,118,443 
Trading tools and subscriptions   343,360    375,705    1,024,621    1,005,126 
    13,607,440    9,040,990    40,067,843    33,178,321 
Operating income (loss)   (734,691)   (4,638,278)   (1,854,170)   7,677,324 
                     
Other income (expense)                    
Interest expense   (1,009,141)   (604,063)   (2,677,700)   (1,586,340)
Interest income   318,903    47,899    538,802    100,433 
Gain on sale of subsidiary   671,588        671,588     
Gain (loss) on foreign currency exchange   (84,243)   (141,648)   416,866    (402,497)
Realized gain (loss) on sale of marketable securities   (14,861)   62,707    (12,945)   65,655 
Other income   88,929    2,690    170,915    6,010 
    (28,825)   (632,415)   (892,474)   (1,816,739)
Net income (loss)   (763,516)   (5,270,693)   (2,746,644)   5,860,585 
Preferred distributions   (137,268)   (137,268)   (411,804)   (411,804)
Net loss attributable to non-controlling interest   60,617        60,617     
Net income (loss) attributable to common   (840,167)   (5,407,961)   (3,097,831)   5,448,781 
                     
Comprehensive income (loss)                    
Net income (loss)   (763,516)   (5,270,693)   (2,746,644)   5,860,585 
Foreign currency translation adjustment   24,190    141,730    (387,649)   359,858 
Change in fair value of cash flow hedges   871,065    320,739    849,328    78,323 
Unrealized loss on securities   (171,357)   (63,903)   (164,574)   (5,767)
Comprehensive income (loss)  $(39,618)  $(4,872,127)  $(2,449,539)  $6,292,999 
Comprehensive loss attributable to non-controlling interest   60,617        60,617     
Comprehensive income (loss) attributable to members  $20,999   $(4,872,127)  $(2,388,922)  $6,292,999 

 

See notes to consolidated financial statements.

 

 11 
 

 

 

Aspirity Holdings LLC and Subsidiaries

Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2015 and 2014

 

   Nine Months 
   Ended September 30, 
   2015   2014 
   Unaudited   Unaudited 
Cash flows from operating activities          
Net income (loss)  $(2,746,644)  $5,860,585 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:          
Gain on sale of subsidiary   (671,588)    
Loss on settlement agreement       3,605,824 
Depreciation and amortization   536,120    645,463 
(Gain) loss on sale of marketable securities   12,945    (65,655)
(Increase) decrease in:          
Trading accounts and deposits   7,159,093    (9,084,679)
Accounts receivable - trade   (2,065,539)   (1,244,420)
Costs in excess of billings   124,617     
Note receivable   (676,546)    
Prepaid expenses and other assets   88,769    (156,204)
Increase (decrease) in:          
Accounts payable - trade   1,243,733    624,086 
Accrued expenses   1,060,740    (328,158)
Billings in excess of costs   (310,845)    
Accrued compensation   (3,633,991)   545,365 
Accrued interest   463,482    331,039 
Obligations under settlement agreement   (194,188)    
Net cash provided by operating activities   390,158    733,246 
           
Cash flows from investing activities          
Repayment of note receivable       140,964 
Purchase of marketable securities   (2,793,871)   (913,534)
Sale of marketable securities   2,537,965    1,229,426 
Purchase of convertible notes   (113,752)   (1,566,545)
Purchase of property, equipment and furniture   (373,996)   (178,210)
Proceeds from sale of real estate held for development   130,965     
Increase in cost of real estate held for development   (480,908)   (88,009)
Increase in restricted cash       (999,183)
Payments on obligations under non-competition agreement       (187,501)
Acquisition of Discount Energy Group, LLC       (680,017)
Acquisition of Noble Conservation Solutions, Inc., net of cash acquired   68,495     
Net cash used in investing activities   (1,025,102)   (3,242,609)
           
Cash flows from financing activities          
Deferred financing costs   (300,792)    
Proceeds from line of credit       700,000 
Repayments of line of credit   (725)    (700,000)
Repayments of senior notes   (216,150)   (201,705)
Proceeds from revolvers   22,552,000     
Repayments of revolvers   (20,993,622)    
Issuances of renewable unsecured subordinated notes   7,806,195    6,899,777 
Redemptions of renewable unsecured subordinated notes   (2,779,224)   (762,817)
Distributions - preferred   (411,804)   (411,804)
Distributions - common   (5,732,215)   (3,626,730)
Net cash provided by (used in) financing activities   (76,337)    1,896,721 
           
Net decrease in cash   (711,281)   (612,642)
           
Effect of exchange rate changes on cash   660,105    359,858 
           
Cash - unrestricted          
Beginning of period   2,397,300    3,190,495 
End of period  $2,346,124   $2,937,711 

 

See notes to consolidated financial statements.

 

 12 
 


Aspirity Holdings LLC and Subsidiaries

Consolidated Statements of Cash Flows (Continued)

Nine Months Ended September 30, 2015 and 2014

 

 

   Nine Months 
   Ended September 30, 
   2015   2014 
   Unaudited   Unaudited 
Non-cash investing and financing activities:          
Effective portion of cash flow hedges  $(14,080)  $434,937 
Unrealized (loss) on marketable securities  $(153,458)  $ 
Note receivable from sale of subsidiary, gross  $14,186,727   $ 
Less: deferred gain on sale   (11,371,573)    
Note receivable from sale of subsidiary, net  $2,815,154   $ 
Land held for development obtained via foreclosure on mortgage loan  $   $353,504 
Acquisition of land held for development via assignment and assumption agreement  $1,083,675   $ 
Acquisition of property, plant, and equipment via mortgage loan  $   $228,000 
           
Supplemental disclosures of cash flow information:          
Cash payments for interest  $2,212,140   $1,255,301 
Capitalized interest related to land held for development  $41,252   $ 

 

See notes to consolidated financial statements.

 

 13 
 

 

 

Aspirity Holdings LLC and Subsidiaries

Notes to Consolidated Financial Statements

 

1.Basis of Presentation and Description of Business

 

Basis of Presentation

 

Aspirity Holdings LLC (“Aspirity” or the “Company”), formerly known as Twin Cities Power Holdings, LLC or “TCPH” prior to July 14, 2015, has prepared the foregoing unaudited consolidated financial statements in accordance with GAAP and the requirements of the SEC with respect to interim reporting. As permitted under these rules, certain footnotes and other financial information required by GAAP for complete financial statements have been condensed or omitted. The interim consolidated financial statements include all normal and recurring adjustments that are necessary for a fair presentation of our financial position and operating results and include the accounts of Aspirity and its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

 

For additional information, please refer to our audited consolidated financial statements and the accompanying notes for the years ended December 31, 2014 and 2013 included in our 2014 Form 10-K.

 

Businesses

 

Aspirity is a Minnesota limited liability company formed on December 30, 2009. On November 14, 2011, the Company entered into an Agreement and Plan of Reorganization (the “Reorganization”) with its then current members and Twin Cities Power, LLC (“TCP”), Cygnus Partners, LLC (“Cygnus”), and Twin Cities Energy, LLC (“TCE”) which were affiliated through common ownership. Effective December 31, 2011, following receipt of approval from the Federal Energy Regulatory Commission (“FERC”), the members of TCP, CP, and TCE each contributed all of their ownership interests in these entities to TCPH in exchange for ownership interests in TCPH, which made TCPH a holding company and the sole member of each of TCP, CP, and TCE. The Reorganization was accounted for as a transaction among entities under common control.

 

Since then, the Company has formed additional first- and second-tier subsidiaries. First-tier subsidiaries include Apollo Energy Services, LLC (“Apollo”), formed on October 27, 2014 for the purpose of providing centralized services to the Company’s various other subsidiaries. Substantially all of the management rights and certain of the direct employees of TCPH were transferred to Apollo as of January 1, 2015. Retail Energy Holdings, LLC (“REH”) was formed on October 25, 2013 in anticipation of the acquisition of Discount Energy Group, LLC or “DEG” and Cyclone Partners LLC (“Cyclone”) was formed on October 23, 2013 to take advantage of certain investment opportunities present in the residential real estate market.

 

With respect to second-tier subsidiaries, as of March 31, 2015, TCP had three active subsidiaries - Summit Energy, LLC (“SUM”), Chesapeake Trading Group, LLC (“CTG”), and Minotaur Energy Futures, LLC (“MEF”), formed on March 25, 2014. Effective April 30, 2015, TCP distributed the ownership interests of CTG to TCPH and it became a first tier subsidiary of the Company. MEF was deactivated in the second quarter of 2015. Cygnus has one subsidiary - Cygnus Energy Futures, LLC (“CEF”). REH has three subsidiaries - Town Square Energy, LLC (“TSE”), Town Square Energy East, LLC (“TSEE”, formerly DEG), and Town Square Energy Canada, Ltd. (“TSEC”). TCE and its wholly-owned subsidiary, Twin Cities Power – Canada, Ltd. (“TCPC”), became inactive in the third quarter of 2012.

 

Through its subsidiaries, the Company trades electricity in North American wholesale markets, provides electricity supply services to retail customers in certain states that permit retail choice, and engages in certain investment activities. Consequently, we have three major business segments used to measure our activity – wholesale trading, retail energy services, and diversified investments.

 

 14 
 

 

The Restructuring

 

Since mid-2014, the Board of Governors has been considering ways to better position the business to access capital markets, in particular that for public equity. Ultimately, the Board concluded that the Company’s regulatory exposure and earnings volatility, particularly that related to the wholesale trading business, needed to be substantially reduced or eliminated in order for such efforts to be successful on the desired scale. On May 27, 2015, the Board approved a plan to restructure the business via the sale of TCP, spinning out the remaining legacy businesses as defined below, and recasting the Company solely as a retail energy and financial services business. Overall, the restructuring incorporated several major steps.

 

New first- and second-tier subsidiaries were created to facilitate the process. The new first-tier subsidiaries consisted of Aspirity Energy LLC (“Aspirity Energy”), Aspirity Financial LLC (“Aspirity Financial”), and Krieger Enterprises, LLC (“Enterprises”). The new second-tier entities, subsidiaries of Aspirity Energy, were formed to conduct business in the various areas of the U.S. that benefit from active wholesale and restructured retail electricity markets - Aspirity Energy Northeast LLC (“AENE”), Aspirity Energy Mid-States LLC (“AEMS”), and Aspirity Energy South LLC (“AES”). Aspirity Financial was formed to provide energy-related financial services to companies and households. Enterprises was formed to accept the contribution of the Legacy Businesses as defined below.

 

On June 1, 2015, the Company closed on the sale of TCP and SUM to Angell Energy, LLC, a Texas limited liability company (“Angell”). Pursuant to an Equity Interest Purchase Agreement (“Purchase Agreement”), the Company sold 100% of the outstanding equity interests of TCP (which included the equity of SUM) to Angell for a purchase price of $20,740,729, paid with $500,000 cash and a secured promissory note of $20,240,729 bearing interest at an annual rate of 6.00% and payable in 12 quarterly installments of $1,855,670 each. The Company and Angell also entered into a security and guarantee agreement and Apollo and Angell entered into software license and administrative services agreements. In selling TCP, the Company partially accomplished its goal of substantially reducing its regulatory exposure and earnings volatility.

 

After closing, Angell decided that it no longer desired to sublease the Lakeville office of TCP nor employ the associated personnel. Angell offered the Company the opportunity to cancel the sublease and to re-employ such personnel in exchange for a reduction of the purchase price. Consequently, an amendment to the Purchase Agreement, effective September 2, 2015, was executed. The amendment reduced the purchase price to $15,000,000 and the note balance to $15,024,573. See also “Note 2 - Summary of Significant Accounting Policies – Variable Interest Entities” and “Note 8 – Notes Receivable”.

 

Effective July 1, 2015, the Company completed an internal reorganization that effected the separation of the Company’s wholesale energy trading, real estate investments, investments in private companies, legacy retail energy business, and certain other assets and obligations (collectively, the “Legacy Businesses”) from its new Aspirity subsidiaries.

 

 15 
 

 

Specifically, the internal reorganization consisted of the following actions:

 

·The Company contributed the following assets to Enterprises:
o100% of the outstanding equity interests of each of Apollo, CTG, Cygnus, and Cyclone;
o100% of the financial rights associated with the equity of REH, with the governance rights to be contributed upon receipt of approval of the transfer from FERC;
o100% of the outstanding equity interests of the following wholly-owned non-operating or inactive subsidiaries:
§Athena Energy Futures LLC;
§Minotaur Energy Futures LLC;
§Twin Cities Energy LLC and its subsidiary Twin Cities Power-Canada, Ltd.;
§TC Energy Trading, LLC;
§Twin Cities Power Services, LLC; and
§Vision Consulting, LLC; and
oCertain other assets and obligations held or owned directly by the Company but not related to the planned operations of the Company following the restructuring, including:
§The Angell note;
§The Series C Convertible Promissory Notes of Ultra Green Packaging, Inc.;
§The Company’s investments in certain real estate projects; and
§The restricted cash pledged to a Canadian court in connection with the Company’s ex-employee litigation; and

 

·Aspirity Financial lent Enterprises an aggregate principal amount of $22,206,113 with a weighted average interest rate of 14.08% and a maturity date of December 30, 2019 (the “Term Loan”). Although initially an intercompany relationship, and eliminated in consolidation, the loan agreement between the parties is constructed on an arm’s length basis, contains customary protective provisions for the lender, including certain guarantees, collateral, and covenants, and ensures that the cash flows generated by the Legacy Businesses may continue to be used to pay the interest and principal on the Company’s outstanding Renewable Unsecured Subordinated Notes (the “Notes”).

 

The last major step in the restructuring is the “Distribution” of 100% of the equity interests of Enterprises to the Company’s common equity owners, thus completing the legal separation of the Legacy Businesses from the Aspirity companies.

 

Declaration and execution of the Distribution is subject to two major conditions precedent:

·Receipt of approval of the holders of a majority by principal amount of the Company’s outstanding Notes. This condition was satisfied on June 26, 2015.
·Declaration of effectiveness of the Company’s new Registration Statement on Form S-1 regarding the sale of up to $75 million of Notes, filed May 8, 2015 (the “New Registration Statement”). This condition was satisfied on November 12, 2015. See “Note 21 - Subsequent Events”.

 

Under the terms of the Indenture governing the Notes, the disposition of all or substantially all of the Company’s assets requires the affirmative approval of the holders of a majority by principal amount of Notes. Enterprises and the Legacy Businesses constitute a majority of the Company’s assets, and consequently, on June 3, 2015, a proposal was submitted to the 565 holders of the $21,914,968 of Notes outstanding as of May 27, 2015, asking them to approve the transfer of the Legacy Businesses to Mr. Timothy S. Krieger and Summer Enterprises, LLC, the owners of the Company’s common equity interests. Noteholders were asked to vote YES or NO to the proposal by June 26, 2015, with an abstention counting as a NO. The Company received YES votes from holders of $15,028,720 in principal amount of Notes representing 68.6% of the total outstanding and 137% of the number required to pass the measure. Holders of $202,421 and $6,683,797 in principal amount of Notes voted NO and abstained, respectively.

 

 16 
 

 

After the Distribution, the Company will no longer be directly exposed to the regulatory risks and earnings volatility of the wholesale trading business. It will have operations in two business segments, Aspirity Financial in financial services and Aspirity Energy in the retail energy business, the provisions of the Notes will not change, and it will remain a SEC reporting company.

 

Wholesale Trading

 

The Company trades financial and physical contracts in wholesale electricity markets managed by Independent System Operators or Regional Transmission Organizations (collectively, the “ISOs”) and regulated by FERC, including those managed by the Midcontinent Independent System Operator (“MISO”), the PJM Interconnection (“PJM”), ISO New England (“ISO-NE”), and the New York Independent System Operator (“NYISO”). We also are members of the Electric Reliability Council of Texas (“ERCOT”) which is an ISO regulated by the Texas Public Utilities Commission and the Texas Legislature. The Company also trades electricity and other energy-related commodities and derivatives on exchanges operated by the Intercontinental Exchange® (“ICE”), the Natural Gas Exchange Inc. (“NGX”), and the CME Group (“CME”), all of which are regulated the Commodity Futures Trading Commission (“CFTC”).

 

As of June 1, 2015 with the sale of TCP the Company no longer is trading in ISO-NE, NYISO, or ERCOT.

 

Retail Energy Services

 

On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC, a retail energy supplier serving residential and small commercial markets in Connecticut. The business was re-named TSE, and beginning on July 1, 2012, the Company began selling electricity to retail accounts. Initially, TSE was run as a division of TCP but effective June 1, 2013, TSE was reorganized as a wholly-owned subsidiary of the Company. During late 2012 and early 2013, TSE applied for retail electricity supplier licenses for the states of Massachusetts, New Hampshire, and Rhode Island which were issued on various dates in 2013.

 

On October 25, 2013, in anticipation of receipt of FERC approval of the Company’s acquisition of TSEE formerly known as DEG, a retail energy business licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio, the Company formed REH and transferred the ownership of TSE to this entity. FERC approval of the acquisition was received on December 13, 2013 and the transaction closed on January 2, 2014. Consequently, the retail markets in which the Company competes include Connecticut, Maryland, Massachusetts, New Hampshire, New Jersey, Pennsylvania, Ohio, and Rhode Island.

 

Diversified Investments

 

On October 23, 2013, the Company formed Cyclone as a wholly-owned subsidiary to take advantage of certain investment opportunities present in the residential real estate market. Specifically, Cyclone acquires and develops land for resale, either as improved sites for construction of single- and multi-family homes or as completed dwellings. In addition to real estate investments, the Company’s diversified investments segment includes certain securities issued by privately-held companies and the provision of management services to third parties.

 

 17 
 

 

Effective June 1, 2015 the Company entered into a 12 month agreement with Ultra Green Packaging, Inc. (“Ultra Green”) to provide CEO services. Also on June 1, 2015, the Company entered into two agreements with Angell - a six month contract to provide certain management, operations, and administrative services and a 24 month software license which is subject to renewal for successive one year periods.

 

Effective September 1, 2015, Enterprises, a wholly-owned first-tier subsidiary of the Company, purchased 60% of the issued and outstanding shares of Noble Conservation Solutions, Inc., a Minnesota corporation (“Noble”) from its shareholders for an aggregate purchase price of $875,002. Noble provides construction and consulting services related to improving the energy efficiency of businesses and homeowners. Consequently, after the acquisition date, the Company’s consolidated financial statements include the financial position and results of operations of Noble.

 

2.Summary of Significant Accounting Policies

 

A description of our significant accounting policies is included in the 2014 Form 10-K and our interim consolidated financial statements should be read in conjunction with the financial statements and accompanying notes included in that report.

 

Results for the three and nine month periods ended September 30, 2015 are not indicative of the results expected for the year ending December 31, 2015.

 

Principles of Consolidation

 

The Company evaluates the need to consolidate affiliates based on standards set forth in the FASB’s ASC 810 Consolidation (“ASC 810”). In determining whether we have a controlling interest in an affiliate and the requirement to consolidate the accounts of an entity, management considers factors such as our ownership interest, our authority to make decisions and contractual and substantive participating rights of the limited partners and shareholders, as well as whether the entity is a variable interest entity (“VIE”) for which we have both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could be potentially significant to the VIE. The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries as well as Noble Conservation Solutions, Inc. All significant intercompany transactions and balances have been eliminated in consolidation.

 

Variable Interest Entities

 

The Company follows ASC 810-10-15 guidance with respect to accounting for VIEs. A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any of the characteristics of a controlling financial interest. A variable interest is an investment or other interest that will absorb portions of a VIE’s expected losses or receive portions of the entity’s expected residual returns. Variable interests are contractual, ownership, or other pecuniary interests that change with changes in the fair value of the entity’s net assets. A party is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides the party with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of the power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances.

 

 18 
 

 

At September 30, 2015, an assessment of the relationship between the Company and Angell was performed as a result of the sale of TCP on June 1, 2015. See “Note 1 - Basis of Presentation and Description of Business - Businesses – The Restructuring”. The Company estimates that total assets of Angell immediately after closing were substantially equal to the purchase price. Angell is a VIE since the equity at risk is small compared to the sale price. Further, the Company held a variable interest in the form of the Angell note as adjusted and paid down in the amount of $14,186,727. The receivable amount carried on the Company’s books net of the deferred gain of $11,371,573 is $2,815,154. The Angell note represents the Company’s maximum loss in the VIE. However, the Company has no power to direct any of the activities of Angell, therefore it does not have a controlling financial interest, thus it is not considered a primary beneficiary, and consequently, as of September 30, 2015, the Company did not consolidate Angell. The Company does not provide, nor does it intend to provide, any other financial support to Angell.

 

Cash Equivalents

 

Cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. As of September 30, 2015 and December 31, 2014, the Company had no cash equivalents included in its cash balances.

 

Reclassifications

 

Certain amounts reported in prior periods have been reclassified to conform to the current period’s presentation. There was no effect on members’ equity or net income as previously reported.

 

Revenue Recognition

 

Wholesale Trading

 

The Company’s wholesale trading activities use derivatives such as swaps, forwards, futures, and options to generate trading revenues. These contracts are marked to fair value in the accompanying consolidated balance sheets. The Company’s agreements with the ISOs and the exchanges permit net settlement of contracts, including the right to offset cash collateral in the settlement process. Accordingly, the Company nets cash collateral against the derivative position in the accompanying consolidated balance sheets. All realized and unrealized gains and losses on derivative instruments held for trading purposes are recorded in revenues.

 

Retail Energy Services

 

Revenue from the retail sale of electricity to customers is recorded in the period in which the commodity is consumed, net of any applicable sales tax. The Company follows the accrual method of accounting for revenues whereby electricity consumed by customers but not yet billed under the cycle billing method is estimated and accrued along with the related costs. Changes in estimates are reflected in operations in the period in which they are refined.

 

Diversified Investments

 

Revenues from real estate developments, if any, are recognized at the time of sale closing if all significant conditions are satisfied, including adequate down payment, reasonable assurance of collectability of any notes received, and completion of other contract requirements. Recognition of all or part of the revenue is deferred if any significant conditions are not satisfied. Revenues from administrative services and software licenses are recognized on a monthly basis in accordance with the respective agreements with third parties.

 

 19 
 

 

Revenue from construction services is accounted for using the percentage of completion method on long term contracts. A long term contract is any contract that spans a period-end and is measured on the basis of costs incurred to date to total estimated costs to complete the contract. The cost-to-complete method is used because management considers it to be the best available measure of progress on these contracts. Revenues from cost-plus-fee contracts are recognized on the basis of costs incurred during the period plus the fee earned, measured by the cost to complete method. The financial statements include some amounts that are based on management’s best estimates and judgments. The most significant estimates relate to costs to complete long term contracts. These estimates may be adjusted as more current information becomes available, and any adjustment could be significant.

 

Contract costs include all direct material and labor costs and certain indirect costs related to contract performance such as indirect labor, supplies, tools, and repairs. Selling, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined.

 

The asset “costs and estimated earnings in excess of billings on uncompleted contracts” represents revenues recognized in excess of amounts billed. The liability “billings in excess of costs and estimated earnings on uncompleted contracts” represents billings in excess of revenues recognized.

 

Derivative Instruments

 

In our wholesale operations, we use derivative contracts for trading purposes, seeking to profit from perceived opportunities driven by expected changes in market prices.

 

In our retail operations, we are exposed to volatility in the cost of energy acquired for sale to customers, and as a result, we use derivatives to hedge or reduce this variability. We follow ASC 815, Derivatives and Hedging (“ASC 815”) guidance that permits “hedge accounting” under which the effective portion of gains or losses from the derivative and the hedged item are recognized in earnings in the same period. To qualify for hedge accounting, the relationship between the “hedged item” - say power purchases for a given delivery zone - and a derivative used as a “hedging instrument” - say, a swap contract for future delivery of electricity at a related hub - must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis.

 

For these derivatives “designated” as cash flow hedges, the effective portion of any change in the hedging instrument’s fair value is recorded as other comprehensive income and deferred until the change in value of the hedged item is recognized in earnings. Our risk management policies also permit the use of undesignated derivatives which we refer to as “economic hedges”. For an undesignated economic hedge, all changes in the derivative financial instrument’s fair value are recognized currently in revenues.

 

“Hedge effectiveness” is the extent to which changes in the fair value of the hedging instrument offset the changes in the cash flows of the hedged item. Conversely, “hedge ineffectiveness” is the measure of the extent to which the change in fair value of the hedging instrument does not offset those of the hedged item. If a transaction qualifies as a “highly effective” hedge, ASC 815 permits matching of the timing of gains and losses of the hedged item and the hedging instrument.

 

 20 
 

Financial Instruments

 

The Company holds various financial instruments. The nature of these instruments and the Company’s operations expose the Company to foreign currency risk, credit risk, and fair value risk.

 

Foreign Currencies

 

A portion of the Company’s assets and liabilities are denominated in Canadian dollars and are subject to fluctuations in exchange rates. The Company does not have any exposure to any highly inflationary foreign currencies.

 

Balance sheet accounts are translated at exchange rates in effect at the end of the month and income statement accounts are translated at average monthly exchange rates for the period. Foreign currency transactions result in gains and losses due to the increase or decrease in exchange rates between periods. Translation gains and losses are included as a separate component of equity. Gains and losses from foreign currency transactions are included in other income or expense. Foreign currency transactions resulted in gains of $24,190 for the three months period ended September 30, 2015 and a loss of $141,730 for the three months period ended September 30, 2014. During the nine months period ended September 30, 2015 and 2014, the Company realized foreign currency losses of $387,649 and $402,497, respectively.

 

Concentrations of Credit Risk

 

Financial instruments that subject the Company to concentrations of credit risk consist principally of deposits in trading accounts and accounts receivable. The Company has a risk policy that includes value-at-risk calculations, position limits, stop loss limits, stress testing, system controls, position monitoring, liquidity guidelines, and compliance training.

 

At any given time, there may be a concentration of receivables balances with one or more of the exchanges upon which we transact our wholesale business or, in the case of retail, one or more of the utilities operating in purchase-of-receivables states in which we do business.

 

Fair Value

 

The fair values of the Company’s cash, accounts receivable, note receivable, accounts payable, and revolver were considered to approximate their carrying values at September 30, 2015 and December 31, 2014 due to the short-term nature of the accounts.

 

Management believes the carrying values of the Notes reasonably approximate their fair values at September 30, 2015 and December 31, 2014 due to the relatively new age of these particular instruments.

 

See also “Note 10 – Fair Value Measurements”.

 

Accounts Receivable

 

Receivables are reported at the amount management expects to collect from outstanding balances. Differences between amounts due and expected collections are reported in the results of operations for the period in which those differences are determined. Receivables are written off only after collection efforts have failed, and the Company typically does not charge interest on past due accounts. As of September 30, 2015 and December 31, 2014 there was an allowance for doubtful accounts of $2,500 and zero, respectively. The allowance at September 30, 2015 related to construction services provided.

 

 21 
 

 

Business Combinations

 

The Company accounts for business combinations in accordance with ASC 805, Business Combinations (“ASC 805”), which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquisition at fair value at the transaction date. The excess of the cost of the acquisition over the interest in the fair value of the identifiable net assets acquired is recorded as goodwill. In addition, transaction costs are expensed as incurred. See “Note 3 - Acquisitions,” “Note 11 - Intangible Assets” and “Note 12 - Goodwill”.

 

Non-Controlling Interest

 

Interests in the operating cooperation held by shareholders are represented by the number of shares owned. The operating cooperation’s income is allocated to holders of stock based upon the ratio of their holdings to the total units outstanding during the period. Capital contributions, distributions, syndication costs, and profits and losses are allocated to non-controlling interests in accordance with the terms of the shareholder agreement.

 

Goodwill

 

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset group to future net undiscounted cash flows expected to be generated by the asset group. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of, if any, are reported at the lower of the carrying amount or fair value less costs to sell. To date, the Company has determined that no impairment of long-lived assets exists.

 

Profits Interests

 

Specific second-tier subsidiaries of the Company have Class B members. Under the terms of the subsidiaries’ member control agreements, Class B members have no voting rights, are not required to contribute capital, and have no rights to distributions following termination of employment, but are entitled to a defined share of profits while employed. Since Class B members have no corporate governance rights or risk of capital loss (or gain), they do not own non-controlling equity interests. Profits interests payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the balance sheet.

 

During the three and nine months ended September 30, 2015 and 2014, the Company included $65,627, $143,421, $2,338,939, and $5,566,883, respectively, in compensation and benefits representing the allocation of profits interests to Class B members.

 

Income Taxes

 

The Company and its subsidiaries are not taxable entities for U.S. federal income tax purposes. As such, the Company and its subsidiaries do not directly pay federal income tax. Taxable income or loss, which may vary substantially from the net income or net loss reported in our consolidated statements of comprehensive income, is includable in the federal income tax returns for each member. The holder of the Company’s preferred units is taxed based on distributions received, while holders of common units are taxed on their proportionate share of the Company’s taxable income. Therefore, no provision or liability for federal or state income taxes has been made for those entities.

 

 22 
 

 

Noble is a Minnesota corporation; thus the Company has elected to use the taxes payable method. Under that method, income tax expense represents the amount of income tax Noble expects to pay based on the entity’s current year taxable income.

 

TCPC files tax returns with the Canada Revenue Agency and the Tax and Revenue Administration of Alberta.

 

In accounting for uncertainty in income taxes, we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. The Company recognizes interest and penalties on any unrecognized tax benefits as a component of income tax expense. Based on evaluation of the Company’s tax positions, management believes all positions taken would be upheld under an examination.

 

The Company’s federal and state tax returns are potentially open to examinations for the years 2011 through 2014 and its Canadian tax returns are potentially open to examination for the years 2011 through 2014.

 

On January 6, 2014, the Company received a notice from the Internal Revenue Service notifying that the Company’s 2012 return was under review. On July 31, 2014, the Company was informed by the IRS that its 2012 return was accepted with no adjustments.

 

New Accounting Pronouncements

 

In April 2015, FASB issued a proposal for a one-year deferral of the effective date of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). Originally, in May 2014, the FASB issued new accounting guidance related to revenue recognition. This new standard will eliminate all industry-specific guidance and replace all current U.S. GAAP guidance on the topic. The new revenue recognition standard provides a unified model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration for which the entity expects to be entitled in exchange for those goods or services. The Company was originally required to adopt the standard on January 1, 2017. Subsequently, the FASB proposed a one-year deferral of the effective date for this standard and the deferral was adopted in August 2015. The Company is now required to adopt the standard on January 1, 2018. Early application is not permitted. The update may be applied using one of two methods, either retrospective application to each prior reporting period presented or retrospective application with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently assessing the impact on the Company’s consolidated financial statements.

 

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835) simplifying the presentation of debt issuance costs. The new guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The recognition and measurement guidance for debt issuance costs are not affected by the new guidance. This guidance is effective for annual and interim periods beginning after December 15, 2015, and early adoption is permitted for financial statements that have not been previously issued. The Company is currently evaluating the impact of ASU 2015-03 on the Company’s consolidated financial position and disclosures.

 

 23 
 

 

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis ("ASU 2015-02"). This amends ASC 810 to improve targeted areas of consolidation guidance by simplifying the requirements of consolidation and placing more emphasis on risk of loss when determining a controlling financial interest. ASU 2015-02 is effective for the annual period ending after December 15, 2015, and subsequent interim and annual periods with early adoption permitted. The adoption of ASU 2015-02 is not expected to have a material impact on the Company's consolidated financial statements.

 

3. Acquisitions

 

Acquisitions are recorded based upon preliminary allocations of the purchase price to management’s assessment of the fair value of tangible and intangible assets and any assumed liabilities acquired. The process of allocating costs to its components involves a considerable amount of subjective judgments, to be made by management, and preliminary estimates of fair values of assets and liabilities acquired are subject to adjustment as additional information is obtained and finalized by management, up to one year after the date of acquisition. Enterprises will finalize the amounts recognized as information necessary to complete the analysis is obtained. Amounts for certain tangible and intangible assets and liabilities remain subject to change. These estimates were based on assumptions the Company believes to be reasonable, however, actual results may differ from these estimates.

 

On August 7, 2015, Enterprises lent Noble $400,000 as bridge financing until the parties completed the negotiation of definitive agreements regarding an equity investment. The note bore interest at a rate of 6% per annum and matured on September 1, 2015. In conjunction with its purchase of Noble, Enterprises committed to lend Noble up to $1,000,000 in the form of a revolving note, which included the $400,000 bridge loan. Any amounts outstanding under the revolver may be repaid at any time without penalty and Noble may borrow available funds from Enterprises upon ten business days’ notice. The note bears interest at a rate of 7.00% per annum, payable quarterly, and matures on August 31, 2020. The revolver is secured by a second position lien on, and security interest in, Noble’s assets. Accrued interest as of September 30, 2015 was $5,753. Amounts owed under the facility are eliminated upon consolidation.

 

Effective September 1, 2015, Enterprises purchased 60% of the issued and outstanding shares of Noble from its shareholders. The consideration for the shares was $875,002 in cash. The Company recognized approximately $714,500 in revenue and $151,500 of a net loss before interest, depreciation, and amortization expense from this entity since the acquisition.

 

 24 
 

 

The consideration for the acquisition of Noble as of the acquisition date consisted of the following:

 

 

Tangible assets:     
Cash - unrestricted  $943,496 
Accounts receivable   1,750,969 
Costs and estimated earnings in excess of billings on uncompleted contracts     151,651  
Property, equipment and furniture, net   285,828 
Other assets   19,980 
Total tangible assets   3,151,924 
      
Intangible assets:     
Contract backlog   425,000 
Goodwill   1,555,277 
Total assets  $5,132,201 
      
Liabilities assumed:     
Revolver  $313,603 
Accounts payable   1,457,436 
Accrued expenses   1,638 
Billings in excess of costs and estimated earnings on uncompleted contracts     777,345  
Accrued compensation   56,441 
Accrued interest   2,078 
Note payable   1,065,323 
Total liabilities   3,673,864 
      
Noncontrolling interest   583,335 
Total equity and liabilities  $4,257,199 
Net assets acquired  $875,002 

 

The following unaudited pro forma information presents a summary of consolidated results of operations of the Company as if the acquisitions occurred at January 1, 2014, the beginning of the earliest period presented. The unaudited pro forma condensed consolidated financial information is presented for informational purposes only. The pro forma information is not necessarily indicative of what the financial position or results of operations actually would have been had the acquisitions been completed on the dates indicated. In addition, the unaudited pro forma condensed consolidated financial information does not attempt to project the future financial position or operating results of the Company after completion of the acquisition.

 

   Three Months   Nine Months 
   Ended September 30,   Ended September 30, 
   2015   2014   2015   2014 
   Unaudited   Unaudited   Unaudited   Unaudited 
Revenue  $14,311,276   $4,915,967   $42,288,104   $42,373,600 
Net income (loss)  $(1,307,232)  $(5,531,029)  $(3,690,451)  $4,886,131 
Net income (loss) attributable to Aspirity Holdings, LLC  $(900,784)  $(5,407,961)  $(3,158,448)  $5,448,781 

 

 

 

 25 
 

 

4. Cash

 

The Company deposits its unrestricted cash in financial institutions. Balances, at times, may exceed federally insured limits.

 

Restricted cash at September 30, 2015 and December 31, 2014 was $1,319,371. All restricted cash was posted as security in connection with certain litigation in the Canadian courts. See “Note 19 - Commitments and Contingencies”.

 

Cash held in trading accounts may be unavailable at times for immediate withdrawal depending upon trading activity. Cash needed to meet credit requirements for outstanding trades and that was available for immediate withdrawal as of September 30, 2015 and December 31, 2014 was as follows:

 

   September 30,   December 31, 
   2015   2014 
Credit requirement  $2,622,874   $6,113,160 
Available credit   6,298,600    14,986,492 
Cash in trading accounts  $8,921,474   $21,099,652 

  

5.Accounting for Derivatives and Hedging Activities

 

The following table lists the fair values of the Company’s derivative assets and liabilities as of September 30, 2015 and December 31, 2014:

 

   Fair Value 
   Asset
Derivatives
   Liability
Derivatives
 
At September 30, 2015          
Designated as cash flow hedges:          
Energy commodity contracts  $   $(14,080)
           
Not designated as hedging instruments:          
Energy commodity contracts   941,240    (980,959)
Total derivative instruments   941,240    (995,039)
Cash deposits in collateral accounts   8,975,273     
Cash in trading accounts, net  $9,916,513   $(995,039)
           
At December 31, 2014          
Designated as cash flow hedges:          
Energy commodity contracts  $15,732   $(879,140)
           
Not designated as hedging instruments:          
Energy commodity contracts   2,350,662    (2,556,862)
FTRs   1,435,819     
Total derivative instruments   3,802,213    (3,436,002)
Cash deposits in collateral accounts   20,733,441     
Cash in trading accounts, net  $24,535,654   $(3,436,002)

 

For the three months ended September 30, 2015, the Company hedged the cost of 58,080 MWh via designated derivatives or 48.14% of the 120,649 MWh of electricity sold to its retail customers in such period.

 

For the nine months ended September 30, 2015, the Company hedged the cost of 92,355 MWh via designated derivatives or 34.36% of the 268,796 MWh of electricity sold to its retail customers in such period.

 

During the three and nine month periods ended September 30, 2015, in addition to derivatives, REH also entered into fixed price electricity purchase contracts with certain wholesale suppliers to lock in margins.

 

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As of September 30, 2015, we had designated futures contracts for 352 MWh for delivery in the remainder of 2015 as cash flow hedges of expected electricity purchases for customers receiving service from us as of that date. $14,080 of the net loss on the 2015 contracts was deferred and included in accumulated other comprehensive income (“AOCI”). This amount is expected to be reclassified to cost of retail electricity sold by December 31, 2015.

 

As of December 31, 2014, we had hedged the cost of 48,947 MWh (approximately 10.5% of expected 2015 electricity purchases for the customers receiving service from us as of that date) and $863,408 of the net loss on the effective portion of the hedge was deferred and included in AOCI. This amount is expected to be reclassified to cost of retail electricity sold by December 31, 2015.

 

The following table summarizes the amount of gain or loss recognized in AOCI or earnings for derivatives designated as cash flow hedges for the periods indicated:

 

   Gain (Loss) Recognized in AOCI   Income
Statement
Classification
  Gain (Loss) Reclassified from AOCI 
Three Months Ended September 30, 2015             
Cash flow hedges  $72,148   Cost of retail electricity sold  $(798,917)
              
Nine Months Ended September 30, 2015             
Cash flow hedges  $(860,592)  Cost of retail electricity sold  $(1,709,920)
              
Year Ended December 31, 2014             
Cash flow hedges  $(1,128,514)  Cost of retail electricity sold  $91,508 

 

The following table provides details with respect to changes in AOCI as presented in our consolidated balance sheets, including those relating to our designated cash flow hedges, for the three and nine month periods from ended September 30, 2015:

 

   Foreign
Currency
   Cash Flow
Hedges
   Available
for
Sale
Securities
   Total 
                 
Three Months ended September 30, 2015                    
Balance - June 30, 2015  $587,202   $(885,145)  $17,899   $(280,044)
Other comprehensive income (loss) before reclassifications   24,190    72,148    (171,357)   (75,019)
Amounts reclassified from AOCI       798,917        798,917 
Net current period other comprehensive income (loss)   24,190    871,065    (171,357)   723,898 
                     
Balance - September 30, 2015  $611,392   $(14,080)  $(153,458)  $443,854 
                     
Nine Months ended September 30, 2015                    
Balance - December 31, 2014  $999,041   $(863,408)  $11,116   $146,749 
Other comprehensive income (loss) before reclassifications   (387,649)   (860,592)   (164,574)   (1,412,815)
Amounts reclassified from AOCI       1,709,920        1,709,920 
Net current period other comprehensive income (loss)   (387,649)   849,328    (164,574)   297,105 
                     
Balance - September 30, 2015  $611,392   $(14,080)  $(153,458)  $443,854 

 

 

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6.Accounts Receivable

 

Accounts receivable consists of receivables from our wholesale trading, retail, and diversified investment segments. Receivables due to wholesale trading activity represent net settlement amounts due from a market operator or an exchange while those from other business lines include amounts resulting from sales to end-use customers.

 

   September 30,   December 31, 
   2015   2014 
Wholesale trading  $42,099   $515,999 
Retail energy services - billed   3,553,373    1,158,019 
Retail energy services - unbilled   1,023,000    720,228 
Diversified investments   37,382     
Construction services   1,557,399     
Allowance for doubtful accounts   (2,500)    
Accounts receivable - trade, net  $6,210,753   $2,394,246 

 

As of September 30, 2015, there was one account in the retail energy service segment with a balance greater than 10% of the total and representing 45% of all receivables.

 

As of December 31, 2014, there were two individual accounts with receivable balances greater than 10%; one in the wholesale segment, representing 21% of the total balance and one in the retail energy services segment, representing 44%.

 

The Company believes that any risk associated with these concentrations is minimal.

 

7.Costs and Estimated Earnings on Uncompleted Contracts

 

The following is a summary of contracts in progress at September 30, 2015:

 

Costs incurred on uncompleted contracts  $1,899,113 
Estimated earnings   629,170 
    2,528,283 
Less: billings to date   (2,967,749)
   $(439,466)

 

Costs and estimated earnings in excess of billings on uncompleted billings  $27,034 
Billings in excess of costs and estimated earnings on uncompleted contracts   (466,500)
   $(439,466)

 

As of September 30, 2015, the Company had under contract uncompleted work with bid prices of $3,676,000 and estimated costs to complete these bids of approximately $851,000.

 

As of September 30, 2015 Noble had total contracts in backlog of $770,000 with an estimated gross profit of $210,000.

 

 

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8.Marketable Securities

 

The following table shows the cost and estimated fair value of available-for-sale securities at September 30, 2015 and December 31, 2014:

 

   Cost   Gross
Unrealized
Gains
   Gross
Unrealized
Losses
   Fair
Value
 
At September 30, 2015                    
U.S. equities  $817,640   $10,977   $(159,394)  $675,077 
International equities   68,431    671    (4,361)   64,741 
Other Assets   21,361        (1,351)   20,009 
Money market fund   130,347            130,347 
Margin Loan   (500,201)           (500,201)
Total  $537,578   $11,648   $(165,106)  $389,974 
                     
At December 31, 2014                    
U.S. equities  $299,836   $11,116   $   $310,952 
Money market fund   634            634 
Total  $300,470   $11,116   $   $311,586 

 

For the three and nine months ended September 30, 2015 the Company received $0 and $2,793,871, realized a loss of $12,945, and incurred no impairment charges.

 

For the year ended December 31, 2014, the Company had sales of securities and realized a gain of $65,655, and recognized no impairment charges.

 

On August 20, 2015 the Company entered into a margin loan with Royal Bank of Canada for the amount of $500,201. This loan is secured by marketable securities. The loan amount is $500,000, with the remaining amount as accrued interest. The annual interest rate is 2.4%.

 

The following table shows the gross unrealized losses on, and fair value of, securities positions by the length of time such assets were in a continuous loss position as of September 30, 2015 and December 31, 2014:

 

   Less than Twelve Months 
   Unrealized
Losses
   Fair
Value
 
At September 30, 2015          
U.S. equities  $(159,394)  $675,077 
International equities   (4,361)   64,741 
Other Assets   (1,351)   20,009 
           
At December 31, 2014          
International equities  $   $ 

 

 

 

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9.Notes Receivable

 

On June 1, 2015, the Company closed on the sale of 100% of the outstanding equity interests of TCP to Angell pursuant to an Equity Interest Purchase Agreement (the “Purchase Agreement”) for a purchase price of $20,740,704, paid with $500,000 cash and a secured promissory note of $20,240,704 bearing interest at an annual rate of 6.00% and payable in 12 quarterly installments of $1,855,668 each (the “Angell Note”). The Company and Angell also entered into a Security and Guarantee Agreement and a Sublease for certain space and equipment at the Company’s Lakeville office. Apollo and Angell entered into a Software License for Apollo’s proprietary DataLive™ software and an Administrative Services Agreement. The Company assigned all of its rights and obligations under these agreements to Enterprises.

 

On September 2, 2015, Enterprises and Angell entered into a First Amendment to the Purchase Agreement (the “Amendment”), pursuant to which Enterprises agreed to cancel the Sublease, re-employ the associated personnel, and reduce the purchase price to $15,000,000. Concurrently, Angell also executed an Amended and Restated Secured Promissory Note in favor of Enterprises which replaced the Angell Note in a principal amount of $15,024,573 (the “Amended Note”). The Amended Note bears interest at rate of 6% per annum, is payable in 16 quarterly installments beginning September 1, 2015 (with the first installment being $1,142,100 and the remaining 15 installments being $1,063,215), and matures on June 1, 2019. The Amended Note is secured by a first priority security interest in the assets of Angell and TCP and is guaranteed pursuant to the Security and Guarantee Agreement made by Angell, TCP, and Michael Angell, individually, in favor of the Company.

 

The following table summarizes the effect of the sale on the Company’s balance sheet at closing on June 1 and as amended effective September 1, 2015:

 

   At closing
June 1, 2015
   As amended
September 1,
2015
   Change 
Cash in trading accounts  $5,740,729   $5,740,729   $ 
Property, equipment, and furniture, net   128,935        (128,935)
Obligations under settlement agreement   (2,912,825)   (2,912,825)    
Net assets sold, net of liabilities assumed  $2,956,839   $2,827,904   $(128,935)
                
Purchase price  $20,740,729   $15,000,000   $(5,740,729)
Deferred gain   (17,783,890)   (12,043,161)   5,740,729 
Net assets sold, net of liabilities assumed  $2,956,839   $2,956,839   $5,740,729 

 

ASC 450-30-25-1 and SEC SAB Topic 13.A state, in part, that gains should not be recognized prior to their realization, consequently, the Company has deferred the $11,371,573 of gain associated with the sale and recorded such on the balance sheet as an offset to the note receivable. The deferred gain will be recognized on a pro rata basis as payments on the note are received.

 

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Under the terms of the note, in the event of default, Angell has 45 days to cure. If the default is uncured at the end of such period, the holder may declare all or any part of the note immediately due and payable or exercise any other rights and remedies under the Uniform Commercial Code. Interest on the note is accrued monthly and is added to the note’s principal balance. As of September 30, 2015, interest of $70,154 was accrued.

 

On August 20, 2015, Cyclone Partners loaned $317,728 to Copper Creek Development II, LLC on an unsecured basis. The note bears interest at 5% per annum and principal and interest are due on the earlier of demand or July 31, 2017. As of September 30, 2015, $1,610 of interest was accrued.

 

Enterprises loaned Ultra Green $50,000 on July 24, 2015 and an additional $50,000 on September 18, 2015. The notes are secured by a first mortgage on Ultra Green’s production facility in Devil’s Lake, North Dakota and bear interest at 10% per annum. Interest only payments are due beginning September 1, 2015. The notes mature when the sale of the North Dakota facility is closed. In connection with the issuance of these notes, Ultra Green issued the Company two warrants to purchase 50,000,000 shares each of its common stock for $0.01 per share. The warrants expire July 23, 2025 and September 18, 2025. Total accrued interest as of September 30, 2015 was $1,270.

 

The following table shows the notes receivable balance as of:

 

   September 30,   December 31, 
   2015   2014 
Notes receivable  $14,604,455   $ 
Plus: interest receivable   73,034     
Less: deferred gain on sale   (11,371,573)    
Notes receivable, net  $3,305,916   $ 
           
Current          
Note receivable from Angell  $3,478,962   $ 
Deferred gain on sale   (2,788,612)    
Interest receivable   70,154     
Note receivable, net  $760,504   $ 
           
Long term          
Note receivable from Angell  $10,707,765   $ 
Deferred gain on sale   (8,582,961)    
Note receivable from Copper Creek   317,728     
Notes receivable from Ultra Green   100,000     
Interest receivable   2,880     
Notes receivable, net  $2,545,412   $ 

 

Total interest received for the three and nine months ended September 30, 2015 was $304,254.

 

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10.Fair Value Measurements

 

The Fair Value Measurement Topic of FASB’s ASC establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three types of valuation inputs in the fair market hierarchy are as follows:

 

·“Level 1 inputs” are quoted prices in active markets for identical assets or liabilities.

 

·“Level 2 inputs” are inputs other than quoted prices that are observable either directly or indirectly for the asset or liability.

 

·“Level 3 inputs” are unobservable inputs for which little or no market data exists.

 

Financial instruments categorized as Level 1 holdings are publicly traded in liquid markets with daily quotes and include exchange-traded derivatives such as futures contracts and options, certain highly-rated debt obligations, and some equity securities. Holdings such as shares in money market mutual funds that are based on net asset values as derived from quoted prices in active markets of the underlying securities are also classified as Level 1.

 

The fair values of financial instruments that are not publicly traded in liquid markets, but do have characteristics similar to observable market information such as wholesale commodity prices, interest rates, credit margins, maturities, collateral, and the like upon which valuations are based are categorized in Level 2.

 

Financial instruments that are not traded in publicly quoted markets or that are acquired based on prices and terms determined by direct negotiation with the issuer are classified as Level 3. Level 3 securities are carried at book value which management believes approximates fair value, until circumstances otherwise dictate while Level 3 derivatives are adjusted to fair value based on appropriate mark-to-model methodologies.

 

Generally, with respect to valuation of Level 3 instruments, significant changes in inputs will result in higher or lower fair value measurements, any particular calculation or valuation methodology may produce estimates that may not be indicative of net realizable value or reflective of future fair values, and such variations could be material.

 

From time to time, the Company may engage third parties such as appraisers, brokers, or investment bankers to assist management in its valuation and classification of financial instruments.

 

There have been no changes in the methodologies used since December 31, 2014.

 

The following table presents certain assets measured at fair value on a recurring basis as of the dates indicated:

 

   Level 1   Level 2   Level 3   Total 
At September 30, 2015                    
Cash in trading accounts, net  $8,921,474   $   $   $8,921,474 
Marketable securities   890,174            890,174 
Investment in convertible notes           1,718,631    1,718,631 
                     
At December 31, 2014                    
Cash in trading accounts, net  $21,099,652   $   $   $21,099,652 
FTR positions, net           1,435,819    1,435,819 
Marketable securities   311,586            311,586 
Investment in convertible notes           1,604,879    1,604,879 

 

There were no transfers during the nine months ended September 30, 2015 between Levels 1 and 2.

 

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Level 3 Assets

 

The following table reconciles beginning and ending Level 3 fair value financial instrument balances for the nine months ended September 30, 2015:

 

Balance - December 31, 2014  $3,040,698 
      
Total gains and (losses):     
Included in other comprehensive income    
Included in earnings   (1,435,819)
Purchases   113,752 
Sales    
Transfers into Level 3    
Transfers out of Level 3    
Balance - September 30, 2015  $1,718,631 
      
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held as of September 30, 2015  $(1,435,819)

 

11.Intangible Assets

 

On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC (“CP&U”), a retail energy supplier serving residential and small commercial markets in Connecticut, for $160,000. The business has been re-named “Town Square Energy” and is now a wholly-owned second-tier subsidiary of the Company. Of the purchase price, $85,000 was allocated to the acquisition of an existing service contract with an industry-specific provider of transaction management, billing, and customer information software and services, and $75,000 was allocated to customer relationships. The purchase price will be amortized over 36 months using the straight line method.

 

Effective January 1, 2013, in connection with the sale of his units to Mr. Krieger, the Company’s founder, Chairman, Chief Executive Officer, and controlling member, the Company entered into a Non-Competition Agreement (the “NCA”) with David B. Johnson, a current governor of the Company valued at $500,000, to be amortized and paid in equal installments over 24 months.

 

On January 2, 2014, the Company acquired 100% of the outstanding membership interests of Discount Energy Group, LLC (“DEG”) for a total purchase price of $848,527, consisting of $680,017 in cash and $168,510 in assumption of accounts payable. Of this total consideration, $293,869 was allocated to tangible assets including deposits with PJM and certain utilities and prepaid expenses and $554,658 was allocated to intangible assets. Intangible assets acquired included state licenses and utility relationships, the DEG brand name, a fully functional website, active and inactive customer lists, and domain names. The intangible assets will be amortized over 24 months using the straight line method.

 

In connection with the purchase of Noble, $425,000 of the purchase price was allocated to the purchase a contract backlog, representing an intangible asset. The amount represents the future gross profit on the jobs in progress as of August 31, 2015. The amount will be amortized on a straight line basis over the life of the contracts, which is estimated to be fully amortized within one year.

 

   September 30,   December 31, 
   2015   2014 
Other intangibles  $714,658   $714,658 
Non-competition agreement   500,000    500,000 
Contract backlog   425,000     
Less: accumulated amortization   (1,170,397)   (945,509)
Intangible assets, net  $469,261   $269,149 

 

Total amortization of intangible assets for the three and nine month periods ended September 30, 2015 and 2014 was $70,796 and $138,064 and $224,888 and $451,940, respectively, and is included in other general and administrative expenses.

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12. Goodwill

 

Goodwill represents the excess of the purchase price of Noble over the fair value of the net identifiable assets acquired. See “Note 3 – Acquisitions” for a calculation of the goodwill related to the Noble acquisition. Goodwill is reviewed for impairment annually or more frequently if impairment indicators arise.

 

The Company’s estimates of fair value are based on the asset approach.  This approach uses the books of Noble to identify the fair value of the assets and liabilities to determine a net value of the company. Our impairment assessment begins with a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. The qualitative assessment includes restating assets and liabilities on the balances sheet to fair market value where necessary and identifying unrecorded assets and liabilities and what their impact will be on the balance sheet. If it is determined under the qualitative assessment that it is more likely than not that the fair value of a reporting unit is less than its carrying value, then a two-step quantitative impairment test is performed. Under the first step, the estimated fair value of the reporting unit is compared with its carrying value (including goodwill). If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. If the estimated fair value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the enterprise must perform step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the implied fair value of that goodwill.

 

Fair value of the reporting unit under the two-step assessment is determined using a discounted cash flow analysis. The use of present value techniques requires us to make estimates and judgments about our future cash flows. These cash flow forecasts will be based on assumptions that are consistent with the plans and estimates we use to manage our business. The process of evaluating the potential impairment of goodwill is highly subjective and requires significant judgment at many points during the analysis. Application of alternative assumptions and definitions could yield significantly different results.

 

In connection with the our qualitative review as of September 30, 2015, we do not believe the carrying value exceeds the fair value, we will perform our annual goodwill assessment as of December 31, 2015.

 

The Company’s goodwill balance as of September 30, 2015 and December 31, 2014 was $1,555,277 and zero, respectively.

 

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13.Deferred Financing Costs

 

Prior to the May 10, 2012 effective date of its 2012 registration statement, the Company incurred certain professional fees and filing costs associated with the offering totaling $393,990. The Company has capitalized these costs and amortizes them on a monthly basis over the weighted average term of the Notes sold, exclusive of any expected renewals.

 

During the nine month period ended September 30, 2015 the Company incurred $300,792 in professional fees associated with its 2015 registration statement associated with its Notes Offering. Amortization of these costs will begin when the new registration statement becomes effective.

 

On October 14, 2014, the Company entered into a credit agreement with a bank and $35,000 of the associated transaction costs were capitalized and will be amortized over 24 months.

 

   September 30,   December 31, 
   2015   2014 
Renewable unsecured subordinated notes          
2012 registration statement  $393,990   $393,990 
2015 registration statement   300,792     
Revolver   35,000    35,000 
Less: accumulated amortization   (349,640)   (187,246)
Deferred financing costs  $380,142   $241,744 

 

Total amortization of deferred financing costs for the three and nine month periods ended September 30, 2015 and 2014 was $59,850 and $33,751 and $162,394 and $88,822, respectively and is included in other general and administrative expenses.

 

14. Real Estate Held for Development

 

As of September 30, 2015 and December 31, 2014 land held for development consisted of $2,387,079 and $953,462, respectively.

 

On January 26, 2015, Cyclone closed on the purchase of a single family home located in New Prague, Minnesota for a price of $198,650, paid in cash. On April 13, 2015, the property was sold to Mr. Krieger, a related party, for a price of $197,382.

 

 

15. Convertible Promissory Note

 

During 2014, the Company invested $1,500,000 in privately placed Series C Convertible Promissory Notes issued by Ultra Green Packaging, Inc. (“Ultra Green”). Ultra Green develops, manufactures, and markets “ecopaper” products made from wheat straw, bamboo, or sugarcane fibers and bioplastic products made from cornstarch. Ultra Green’s ecopaper and bioplastic products are certified as biodegradable and sustainable, and are compostable in about 160 days.

 

In addition to its cash investments as described above, the Company has lent the services of Mr. Keith Sperbeck, its Vice President – Operations, to Ultra Green as its Interim CEO for an indefinite period concluding when Ultra Green hires a full-time chief executive officer. In lieu of any cash compensation to either Mr. Sperbeck or the Company, on June 19, 2014, Ultra Green issued the Company a non-statutory option to purchase 50,000,000 shares of its common stock for $0.01 per share, which option was fully vested and exercisable immediately upon issuance.

 

The C Notes will mature on December 31, 2019 and bear interest at a fixed rate of 10% per annum. Interest will accrue until June 30, 2016, at which time all accrued and unpaid interest will become due and payable. Thereafter, interest will be due and payable on a quarterly basis. Each dollar of C Note principal and accrued but unpaid interest is ultimately convertible into 100 shares of Ultra Green’s common stock.

 

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16. Debt

 

Notes payable by the Company are summarized as follows:

 

   September 30,
2015
   December 31,
2014
 
Demand and Revolving Debt          
Payable to ABN AMRO  $   $ 
Revolving note payable to US Bank   67,178     
Revolving note payable to Citizens   245,700     
Revolving note payable to Maple Bank   2,663,637    1,105,259 
Subtotal   2,976,515    1,105,259 
           
Term Debt          
Auto note payable to Ally Financial   22,100     
Auto note payable to Ford Credit   26,357     
Mortgage note payable to Security State Bank   219,262    224,568 
Mortgage note payable to Lakeview Bank   119,976    119,976 
Construction note payable to American Land & Capital   1,074,672    184,975 
Renewable unsecured subordinated notes   22,680,099    17,653,128 
Subtotal   24,142,466    18,182,647 
Total  $27,118,981   $19,287,906 

 

Notes payable by maturity are summarized as follows:

 

   September 30,
2015
   December 31,
2014
 
Demand and Revolving Debt          
2016   2,976,515    1,105,259 
Subtotal   2,976,515    1,105,259 
           
Term Debt          
2015       7,546,627 
2016 to September 30   10,636,397     
Current maturities   10,636,397    7,546,627 
           
2016 after September 30   4,229,146     
2016   4,174,962    2,648,150 
2017   2,546,624    2,869,383 
2018   816,245    2,642,972 
2019   9,385    1,213,227 
2020 & thereafter   1,729,707    1,262,288 
Long term debt   13,506,069    10,636,020 
Subtotal   24,142,466    18,182,647 
Total  $27,118,981   $19,287,906 

 

 

 

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ABN-AMRO Margin Agreement

 

In February 2012, the Company executed a Futures Risk-Based Margin Finance Agreement (“Margin Agreement”) with ABN AMRO. The Margin Agreement provides CEF with an uncommitted $25,000,000 revolving line of credit on which it pays a commitment fee of $35,000 per month. Any loans outstanding are payable on demand and bear interest at an annual rate equal to 1.00% in excess of the Federal Funds Target Rate, or approximately 1.25%. The Margin Line is secured by all balances in CEF’s trading accounts with ABN AMRO. Under the Margin Agreement, the Company is also subject to certain reporting, affirmative, and negative covenants, including certain financial tests. The Margin Agreement was amended on May 31, 2013 to reduce the uncommitted credit line to $15,000,000, the commitment fee to $25,000 per month, and the covenant with respect to net liquidating equity as defined to $1,500,000.

 

As of September 30, 2015 and December 31, 2014, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants.

 

RBC Line of Credit

 

On May 14, 2014, the Company drew $700,000 under an evergreen, uncommitted line of credit from Royal Bank of Canada (the “RBC Line” and “RBC”, respectively). Advances under the RBC Line bear interest at a variable annual interest rate of 1 month LIBOR plus 2.25% set at the time of advance for a 30 day term, mature at various dates, and are collateralized by assets held in the Company’s marketable securities account. RBC is not obligated to make any extensions of credit to the Company and availability of funds may be increased or decreased by RBC in its sole and absolute discretion. Prepayment of any outstanding principal under the RBC Line may subject the Company to LIBOR break funding costs.

 

As of September 30, 2015 and December 31, 2014, there were no borrowings respectively outstanding under the RBC Line and the Company was in compliance with all terms and conditions.

  

Maple Bank Revolver

 

On October 14, 2014, REH, TSE, and TSEE entered into a Credit Agreement with the Toronto, Ontario branch of Maple Bank GmbH (the “Maple Revolver” and “Maple Bank”), expiring October 31, 2016. The Maple Revolver provides the Company’s retail energy services businesses with a revolving line of credit of up to $5,000,000 in committed amount secured by a first position security interest in all of the assets, a pledge of the equity of such companies by the Company, and certain guarantees. Availability of loans is keyed to advance rates against certain eligible receivables as defined. Any loans outstanding bear interest at an annual rate equal to 3 month LIBOR, subject to a floor of 0.50%, plus a margin of 6.00%. In addition, the Company is obligated to pay an annual fee of 1.00% of the committed amount on a monthly basis and a monthly non-use fee of 1.00% of the difference between the committed amount and the average daily principal balance of any outstanding loans. The Company is also subject to certain reporting, affirmative, and negative covenants. On August 4, 2015 the Maple Revolver was amended to increase the committed amount to $7,500,000.

 

As of September 30, 2015 and December 31, 2014, there was $2,663,637 and $1,105,259, respectively, outstanding under the Maple Revolver and the Company was in compliance with all covenants. 

 

Citizens Independent Bank

 

On July 24, 2014, Noble, entered into a line of credit agreement with Citizens Independent Bank, expiring August 1, 2015. The agreement provides Noble with a line of credit of up to $500,000 in committed amount secured by property and assets as the lender may require and guarantees. Availability of loans is keyed to advance rates against certain eligible receivables as defined. Any loans outstanding bear interest at 1% above the base rate established by the bank. Noble is also subject to certain reporting, affirmative, negative covenants, and must pay down the line to $250,000 for a thirty consecutive day period. As of September 30, 2015, there was $245,700 outstanding under the agreement and were in negotiations with the lender on the terms of the line.

 

US Bank Cash Flow Manager

 

On October 21, 2013, Noble, entered into a line of credit agreement with US Bank Cash Flow Manager, with all advances maturing on February 19, 2020. The agreement provides Noble with a line of credit of up to $250,000 in committed amount secured by personal guarantees of the owners of Noble. Any loans outstanding bear interest at an annual rate equal to prime plus 4.5%. As of September 30, 2015, there was $67,178 outstanding under the agreement.

 

Ford Credit

 

On June 13, 2014, Noble entered into a loan agreement with Ford Credit for the purchase of a vehicle. The note calls for sixty monthly payments of $664.43, bears interest at 6.7%, and is secured by the vehicle. As of September 30, 2015, the balance remaining on the note was $26,357.

 

Ally Financial

 

On December 26, 2012, Noble entered in a loan agreement Ally Financial for the purchase of a vehicle. The note calls for seventy two monthly payments of $587.65, bears interest at 4.9%, and is secured by the vehicle. As of September 30, 2015, the balance remaining on the note was $22,100.

 

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Security State Mortgage

 

On June 16, 2014, the Company purchased a single family home in Garrison, Minnesota for use as a corporate retreat (the “Garrison Property”) for a purchase price of $285,000, paid with $57,000 of cash and the proceeds of a $228,000 note (the “Security State Mortgage”) advanced by the Security State Bank of Aitkin (“Security State Bank”) and secured by a first mortgage. The loan is payable in 239 equal installments of $1,482 due on the 16th of each month beginning on July 16, 2014 and one irregular installment due on June 16, 2034 (the “maturity date”). The note bears interest at an annual rate equal to the prime rate as published from time to time by The Wall Street Journal plus 0.75%, subject to a floor of 4.75%. Whenever increases occur in the interest rate, Security State, at its option and with notice to the Company, may: (a) increase the Company’s payments to insure the loan will be paid off by the maturity date; (b) increase the Company’s payments to cover accruing interest; (c) increase the number of the Company’s payments; or (d) continue the payments at the same amount and increase the Company’s final payment. The loan may be prepaid in whole or in part at any time without penalty.

 

As of September 30, 2015 and December 31, 2014, there was $219,262 and $224,568, respectively, outstanding under the Security State Mortgage and the Company was in compliance with all terms and conditions of the loan.

 

Lakeview Bank Mortgage

 

On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon Holdings, LLC (“Kenyon”), a related party, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a note secured by a mortgage on the property and owed to Lakeview Bank (the “Lakeview Bank Mortgage”). Kenyon is owned by Mr. Krieger, the Company’s primary owner and its Chief Executive Officer, and Keith W. Sperbeck, the Company’s Vice President of Operations. The Lakeview Bank Mortgage bears interest at the highest prime rate reported as such from time to time by The Wall Street Journal. Interest only is payable monthly on the 25th, the note matures April 30, 2016. The loan may be prepaid in whole or in part at any time without penalty.

 

As of September 30, 2015 and December 31, 2014, there was $119,976 outstanding under the Lakeview Bank Mortgage and the Company was in compliance with all terms and conditions of the loan.

 

American Land and Capital Construction Loans

 

On November 21, 2014, American Land and Capital, LLC (“American Land”) and Cyclone entered into four construction loan agreements, each for a committed amount of $205,000 or $820,000 in total (the “Fox Meadows Construction Loans”). Each commitment is secured by a mortgage on a lot (numbers 1, 2, 3, and 4) in Block 1 of Fox Meadows 3rd Addition and is personally guaranteed by Mr. Krieger. Fox Meadows is a townhouse development located in Lakeville, Minnesota in which Cyclone owns 35 attached residential building sites. Proceeds of the Construction Loans will be used to construct the first four spec/model homes on Cyclone’s Fox Meadows property. Draws on the Construction Loans bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10th, the notes mature on November 21, 2015, and will renew for an additional three months if not paid by then. The loans may be prepaid in whole or in part at any time without penalty.

 

 

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On February 24, 2015, American Land and Cyclone entered into a construction loan agreement for a committed amount of $485,000 (the “Bitterbush Pass Construction Loan”). The Bitterbush Pass Construction Loan is secured by a mortgage on Lot 2, Block 1, Territory 1st Addition, also referred to as “21580 Bitterbush Pass”. The loan is also personally guaranteed by Mr. Krieger. Proceeds will be used to construct a home on the property and draws bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10th and the note matures on November 24, 2015. The loan may be prepaid in whole or in part at any time without penalty.

 

As of September 30, 2015 and December 31, 2014, there was $1,074,672 and $184,975, respectively, outstanding under the American Land Construction Loans and the Company was in compliance with all terms and conditions of the agreements.

 

Renewable Unsecured Subordinated Notes

 

On May 10, 2012, the Company’s registration statement on Form S-1 with respect to its offering of up to $50,000,000 of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year Renewable Unsecured Subordinated Notes was declared effective by the SEC. Interest on the Subordinated Notes is paid monthly, quarterly, semi-annually, annually, or at maturity at the sole discretion of each investor.

 

On May 8, 2015, the Company filed a replacement registration statement on Form S-1 relating to the offer and sale of our Renewable Unsecured Subordinated Notes (the “2015 S-1”). The 2015 S-1 covers up to $75,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes.

 

The Company made interest payments of $787,900, $466,789, $1,863,528, and $1,006,566 during the three and nine month periods ended September 30, 2015 and 2014, respectively. Total accrued interest on the Subordinated Notes at September 30, 2015 and December 31, 2014 was $1,283,350 and $849,913, respectively.

 

As of September 30, 2015, the Company had $22,680,099 of Subordinated Notes outstanding as follows:

 

Initial Term  Principal Amount   Weighted Average Interest Rate 
3 months  $611,565    10.89%
6 months   195,628    8.81%
1 year   6,684,138    13.42%
2 years   3,325,568    13.67%
3 years   4,210,781    14.92%
4 years   2,454,972    15.92%
5 years   3,636,905    15.93%
10 years   1,560,542    14.96%
Total  $22,680,099    14.41%
           
Weighted average term   33.1 mos      

 

 

 

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17. Ownership

 

As of September 30, 2015 and December 31, 2014, the Company’s ownership is as presented below:

 

   Series A Preferred   Common 
   Units held   Percent of class   Units held   Percent of class 
Timothy S. Krieger   496    100.00%   4,935    99.50%
Summer Enterprises, LLC       0.00%   25    0.50%
Total   496    100.00%   4,960    100.00%

 

For the period ending, September 30, 2015 total common and preferred distributions paid to the owners of the respective units was $5,732,215 and $411,804, respectively.

 

For the year ending December 31, 2014, total common and preferred distributions paid to the owners of the respective units was $4,726,730 and $549,072, respectively. 

 

18. Related Party Transactions

 

On January 1, 2013, the Company and Kenyon entered into a five year lease expiring December 31, 2017 for 11,910 square feet at a monthly rent of $12,264. On September 25, 2014, the lease was amended to reduce the square footage to 10,730 and monthly rent to $11,113. The lease was redone on May 19, 2015, effective June 1, 2015, to reduce the square footage to 8,543 square feet and increase the monthly rent to $14,968. For rent, real estate taxes, and operating expenses, the Company paid Kenyon $44,900, $55,200, $160,500, and $154,000 for the three and nine months ended September 30, 2015 and 2014, respectively.

 

On September 1, 2015, CTG entered into a five year lease agreement with Kenyon for 2,231 square feet of office space for a monthly rent of $4,641. As of September 30, 2015, $9,282 of rent was owed to Kenyon for two months’ rent.

 

Effective January 1, 2013, in connection with the purchase of David B. Johnson’s units by Mr. Krieger, the Company entered into the NCA with Mr. Johnson, a current governor and former member of the Company, pursuant to which the Company is obligated to pay Mr. Johnson $500,000 in 24 equal monthly installments of $20,833 each. The total amount paid pursuant to the NCA during the nine months ended September 30, 2014 was $62,500. There were no payments during 2015 as the NCA was paid in full on December 31, 2014.

 

On March 5, 2013, CEF entered into a 36 month lease for 1,800 square feet of office space in Tulsa, Oklahoma with the Brandon J. and Heather N. Day Revocable Trust at a monthly rent of $3,750. Mr. Day is an employee of CEF, a second-tier subsidiary of the Company. Total rent paid for the three and nine months ended September 30, 2015 and 2014 was $11,250 and $33,750, respectively.

 

In connection with the Company’s initial investment of $1.0 million in Ultra Green, Ultra Green paid a 10% commission to Cedar Point Capital, LLC, a registered broker dealer (“Cedar Point”). David B. Johnson, a governor of the Company, is the sole owner of Cedar Point. No commissions were paid on the Company’s follow-on investments.

 

 

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On June 17, 2014, the building in which the Company leases its Chandler, Arizona office space occupied by certain of its retail business functions was purchased by Fulton Marketplace, LLC (“Fulton”), a company owned by Mr. Krieger and Mr. Sperbeck. Effective August 1, 2014, the Company and Fulton entered into a five year lease expiring July 31, 2019, subject to two consecutive five year extension periods, for 2,712 square feet. The rent for the first lease year is $4,068 per month and it will increase by 3% annually at the start of each lease year thereafter. On June 30, 2015 the Company discontinued the lease as the office was relocated to a new location. Thus, effective July 1, 2015, the Company entered into a new five year lease with Fulton for a 3,321 square foot office space with a monthly base rent of $4,982 that will increase by 3% annually at the start of each lease year thereafter. The Company paid $18,600 and $50,700 to Fulton for the three and nine months ended September 30, 2015 for rent, real estate taxes, and operating expenses.

 

Fulton is also the owner of a single family residence located in Chandler, Arizona. Effective December 1, 2014, Fulton and REH entered into a seven month lease expiring June 30, 2015 with respect to the property for rent of $2,800 per month. For the nine months ended September 30, 2015 the Company paid Fulton total rent of $17,136.

 

On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a note secured by a mortgage on the property and owed to Lakeview Bank. The total acquisition cost paid to Kenyon was $52,000 and represented Kenyon’s total expenditures on the property (interest, closing fees, and property taxes) since its acquisition in 2013.

 

See also “Note 1 - Basis of Presentation and Description of Business - Businesses – The Restructuring”.

 

19. Commitments and Contingencies

 

FERC Settlement

 

On October 12, 2011, FERC initiated a formal non-public investigation into TCE’s power scheduling and trading activity in MISO for the period from January 1, 2010 through May 31, 2011 (the “Investigation”). The Investigation addressed trading activity by former employees of TCPC whose employment contracts were terminated by TCPC on February 1, 2011 in connection with the Company’s reorganization of its Canadian operations. TCE and TCPC have no employees and do not conduct any operations.

 

On June 12, 2014, FERC issued a Notice of Alleged Violations (“NAV”) indicating that the staff of its Office of Enforcement had preliminarily determined that during the period from January 1, 2010 through January 31, 2011, TCPC and certain affiliated companies, including TCE and TCP, and individuals Allan Cho, Jason F. Vaccaro, and Gaurav Sharma, each violated the FERC’s prohibition on electric energy market manipulation by scheduling and trading physical power in MISO to benefit related swap positions that settled based on real-time MISO prices.

 

On November 14, 2014, three subsidiaries of the Company agreed to a settlement regarding the Investigation and the NAV. The settlement required TCE, TCPC, and TCP to collectively pay $978,186 plus interest of $128,827 as disgorgement of profits and $2,500,000 as a civil penalty, for a total of $3,607,013. On December 30, 2014, FERC formally accepted the settlement and on December 31, 2014, MISO was paid $500,000 as disgorgement and beginning with the second quarter 2015, the remainder is to be paid in 16 equal quarterly installments, first to MISO as disgorgement until it is fully paid, and thereafter to the Treasury in satisfaction of the penalty. TCE, TCPC, and TCP further agreed to implement certain procedures to improve compliance. Failure to comply with the terms and conditions will be deemed a violation of the final order and may subject the responsible parties to additional action.

 

On June 1, 2015, TCE’s and TCP - Canada’s financial obligations under the settlement agreement were transferred to Angell in connection with its purchase of TCP.

 

 

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Former Employee Litigation

 

On February 1, 2011, the Company commenced a major restructuring of the operations of TCPC and all personnel were terminated, although several were subsequently re-hired. During the course of 2011, three former employees of TCPC commenced legal proceedings and brought separate summary judgment applications seeking damages aggregating C$3,367,000 for wrongful dismissal and payment of performance bonuses. The Company filed a counterclaim for C$3,096,000 against one of the former employees for losses suffered, inappropriate expenses, and related matters. Two of the three summary judgment applications were dismissed on January 12, 2012. All three summary judgment applications were appealed and were heard on July 4, 5, and 6, 2012 by the Alberta Court of Queen’s Bench. On July 6, 2012, the court dismissed two of the three applications and allowed the third, awarding summary judgment against TCPC for a portion of the claim amounting to C$1,376,726. This third matter will hereinafter be referred to as the “TCPC judgment action”.

 

In 2013, the former employees brought applications to amend their pleadings to include as additional corporate defendants certain TCPC U.S. affiliates (“Twin Cities USA”). One of the former employees proceeded with the application and the others were adjourned. The application that proceeded went forward on April 29 and 30, 2013. In a decision dated January 31, 2014, the Court of Queen’s Bench dismissed the applications to add additional corporate defendants but allowed certain refinements to the pleadings. Thereafter the Company and TCPC consented to an amendment of pleadings of the other employees consistent with the Court’s ruling.

 

In addition, on January 31, 2014 within the “TCPC judgment action” the Court of Queen’s Bench ordered Twin Cities USA to post security for costs in the sum of C$75,000 together with security for judgment in the sum of C$1,376,726. In order to preserve its claims and counterclaims against the former employees in the TCPC judgment action, Twin Cities USA posted security for the judgment and costs and continues to maintain that security pending further order or direction from the Court of Queen’s Bench.

 

Twin Cities USA and TCPC intend to continue to vigorously defend against the allegations and claims of the former employees and have filed counterclaims or amended counterclaims for losses suffered and costs incurred in responding to the FERC investigation, inappropriate expenses, and related matters.

 

Further, on April 24, 2015, the Company commenced a new action against a former employee of TCPC, Guarav Sharma, claiming amounts owing in relation to the FERC settlement arising from his conduct as an employee.

 

In all of this former employee litigation, the parties are proceeding with discovery. A case management justice has been appointed who will assist the parties in scheduling and any required motions.

 

Due to the uncertainty surrounding the outcome of the litigation, including that of its counterclaims against the former employees, the Company is presently unable to determine a range of reasonably possible outcomes.

 

PJM Resettlements

 

On May 11, 2012, FERC issued an order denying rehearing motions in regards to PJM resettlement fees confirming its intent to reverse refunds it had granted to a number of market participants in a 2009 order. These refunds were related to transmission line loss refunds issued to the Company by PJM for prior periods. Pursuant to the order, the Company was required to return $782,000 to PJM which amount was paid in full in July 2012.

 

On July 9, 2012, several parties filed a petition for review of the May 11, 2012 FERC order with the District of Columbia Circuit of the U.S. Court of Appeals and certain subsidiaries of the Company filed motions to intervene in the proceeding. In an order issued August 6, 2013, the Court remanded to FERC for further consideration the issue of recoupment of refunds that had previously been directed by FERC. The Court found that FERC’s orders failed to explain why refund recoupment was warranted and therefore its recoupment directive was found to be arbitrary and capricious.

 

 

 42 
 

 

 

On February 20, 2014, the FERC issued an order establishing a briefing schedule allowing parties to the proceeding to provide briefs on whether or not the recoupment orders should be reconsidered. Although briefing on all issues relevant to the remand was invited by FERC, it also presented five specific questions, primarily relating to the effect of the recoupment orders, for the parties to address. Initial briefs were due on April 6, 2014 and FERC’s reply briefs were due May 6, 2014.

 

Now that briefing is completed, it is expected that FERC will issue an order responding to the Court’s remand directive. If FERC affirms its prior order it is expected that some or all of the financial marketer appellants and interveners will again challenge the lawfulness of the decision on rehearing or before the Court of Appeals. If FERC reconsiders its order and finds that the refunds should not have been recouped, or failing that action, if the Court again finds the FERC order unlawful, then some or all of the funds paid to PJM in July 2012 could be returned to the Company. Due to the uncertainty surrounding the outcome of the remand and appeals process, the Company is presently unable to determine a reasonable estimate of the amount, if any, which could be returned.

 

Finally, management believes that the liability for such charges, if any, associated with TCP and SUM’s trading activity was assumed by Angell in conjunction the sale of the equity interests.

 

PJM Up To Congestion Fees

 

On August 29, 2014, FERC initiated a proceeding under Section 206 of the Federal Power Act, as amended, described in Docket No. EL14-37-000 regarding how PJM treats up-to-congestion (“UTC”) transactions in the market (the “§206 proceeding”). The purpose of the proceeding is for FERC to examine how uplift is, or should be, allocated to all virtual transactions within the PJM market. The Company is an active trader of these UTCs.

 

Currently, under PJM’s Tariff and Operating Agreement, UTCs are treated differently under its FTR forfeiture rule than are INCs and DECs, two other types of virtual transactions. Further, INCs and DECs are subject to uplift charges, but UTCs are not. In Docket No EL14-37-000, FERC noted that should any uplift be charged UTCs, it would apply such back to the date that notice of the proceeding was published in the Federal Register (September 8, 2014), thus setting a “refund effective date”. From the refund effective date to September 30, 2015, the Company traded about 6,500,000 MWh of UTCs in PJM and recorded $13,400,000 of associated revenues. Over 95% of this trading activity was transacted by TCP and SUM.

 

Although the Company’s UTC trading activity exposes it to potential uplift charges, none have been billed as the investigation is still pending. Further, the Company has not established any reserves for such as management is uncertain as to the probability, amount, and timing of the actual payment, if any, that might be due. Finally, management believes that the liability for such charges, if any, associated with TCP and SUM’s trading activity was assumed by Angell in conjunction the sale of the equity interests.

 

Letter of Credit

 

On June 24, 2014, the Company’s restricted cash balance of $320,188 was returned by the City of Lakeville and a letter of credit in favor of Cyclone was issued by Vermillion State Bank for the same amount. The note evidencing the letter of credit calls for maximum advances of up to $320,188, bears interest at an annual rate of 5.25%, is secured by a mortgage on the property being developed and the guaranty of Cyclone, and matures on demand. As of September 30, 2015 the Company was in compliance with all terms and conditions of the letter of credit. In October 2015, the note was renewed for another year, the letter of credit maximum advance dropped to $257,718, with all other terms remaining the same.

 

 

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Guarantees

 

In the ordinary course, the Company provided guarantees of the obligations of TCP, SUM, and CEF with respect to their participation in certain ISOs. During the three month period ended September 30, 2015, many of these guarantees were cancelled.

 

On July 6, 2015, the effective date, the Company gave notice to MISO of the cancellation of its guarantees of TCP, CEF, and SUM’s obligations.

 

On June 17, 2015, REH entered into two separate guaranties of the obligations of TSE and TSEE of up to $1,000,000 in favor of BP Energy Company (“BP”). The guarantees remain effective until the earlier of June 17, 2020 or ten days after REH gives notice of cancellation to BP.

 

On May 13, 2015, the Company gave notice to ERCOT and NYISO of the cancellation of its guarantees of TCP’s obligations, and a concurrent pledge of $500,000 of additional collateral to NYISO. On May 14, 2015, NYISO accepted the collateral and the cancellation of the Company’s obligation. On June 9, 2015, ERCOT accepted the cancellation of the Company’s obligation.

 

On April 13, 2015, the Company pledged additional collateral of $700,000 to PJM and consequently cancelled its guarantees for the benefit of PJM with respect to TCP and SUM effective April 30, 2015.

 

On April 25, 2014, the Company entered into a guaranty of the obligations of TSEE of up to $1,000,000 (plus any costs of collection or enforcement) in favor of Noble Americas Energy Solutions, LLC. The Company may cancel the guarantee upon 30 days’ written notice to Noble Americas Energy Solutions, LLC.

 

On November 5, 2014, the Company entered into two separate guaranties of the obligations of TSE and TSEE of up to $500,000 (plus any costs of enforcement or collection) in favor of Shell Energy North America L.P. (“Shell”). The guarantee is in effect until the earlier of November 5, 2019 or ten days’ after the Company gives notice to Shell of its cancellation.

 

On August 12, 2013, the Company entered into a guaranty of the obligations of TSE of up to $1,000,000 (plus any costs of collection or enforcement) in favor of Noble Americas Energy Solutions LLC. The Company may cancel the guarantee upon 30 days’ written notice to Noble Americas Energy Solutions, LLC.

 

Legal fees, if any, related to commitments and contingencies are expensed as incurred.

 

 

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20. Segment Information

 

The Company has three business segments used to measure its business activity – wholesale trading, retail energy services, and diversified investments:

 

·Wholesale trading activities earn profits from trading financial, physical, and derivative electricity in wholesale markets regulated by the FERC and the CFTC. On June 1, 2015, the Company sold two subsidiaries operating within this segment. See “Note 1 - Basis of Presentation and Description of Business – Businesses – The Restructuring”, “Note 2 – Summary of Significant Accounting Policies – Variable Interest Entities”, and “Note 9 – Notes Receivable”.

 

·On July 1, 2012, the Company began selling electricity to residential and small commercial customers.
  
·On October 23, 2013, the Company formed a new entity to take advantage of certain investment opportunities in the residential real estate market and in 2014, it made certain investments in the securities of emerging companies. On June 1, 2015, the Company began selling management and administrative services and licensing software to third parties. In September 2015, the Company acquired Noble and began offering construction services.

 

Trading profits and sales are classified as “foreign” or “domestic” based on the location where the trade or sale originated. For the three and nine month periods ended September 30, 2015 and the year ended December 31, 2014, all such transactions were “domestic”. Furthermore, the Company has no long-lived assets in foreign jurisdictions.

 

These segments are managed separately because they operate under different regulatory structures and are dependent upon different revenue models. The performance of each is evaluated based on the operating income or loss generated.

 

Certain amounts reported in prior periods have been reclassified to conform to the current period’s presentation.

 

 45 
 

 

Information on segments for the three and nine months ended and at September 30, 2015 is as follows:

 

   Wholesale
Trading
   Retail
Energy
Services
   Diversified Investments   Corporate, Net of Eliminations   Consolidated Total 
Nine Months Ended
September 30, 2015
                         
Wholesale trading, net  $13,362,694   $(281,367)  $   $   $13,081,327 
Retail energy services       23,566,115            23,566,115 
Real estate sales           351,725        351,725 
Management services           500,000        500,000 
Construction services           714,506        714,506 
Revenues, net   13,362,694    23,284,748    1,566,231        38,213,673 
                          
Costs of retail electricity sold       20,350,365            20,350,365 
Cost of construction services           620,426        620,426 
Cost of real estate sold           297,482        297,482 
Retail energy sales and marketing       1,017,774    5,954        1,023,728 
Compensation and benefits   8,453,226    608,537    1,091,557    1,042,676    11,195,996 
Professional fees   44,945    798,005    34,258    1,257,551    2,134,759 
Other general and administrative   3,010,744    1,997,540    185,484    (1,773,302)   3,420,466 
Trading tools and subscriptions   661,092    311,955    1,662    49,912    1,024,621 
Operating costs and expenses   12,170,007    25,084,176    2,236,823    576,837    40,067,843 
Operating income (loss)  $1,192,687   $(1,799,428)  $(670,592)  $(576,837)  $(1,854,170)
                          
Capital expenditures  $102,837   $48,100   $534,354   $169,613   $854,904 
                         
Three Months Ended
September 30, 2015
                         
Wholesale trading, net  $1,258,274   $50,846   $   $   $1,309,120 
Retail energy services       10,122,398            10,122,398 
Real estate sales           351,725        351,725 
Management services           375,000        375,000 
Construction services           714,506        714,506 
Revenues, net   1,258,274    10,173,244    1,441,231        12,872,749 
                          
Cost of retail electricity sold       8,031,489            8,031,489 
Cost of construction services           620,426        620,426 
Cost of real estate sold           297,482        297,482 
Retail sales and marketing       414,868    5,953        420,821 
Compensation and benefits   858,157    218,180    442,844    446,674    1,965,855 
Professional fees   3,988    259,185    32,058    523,028    818,259 
Other general and administrative   28,069    688,770    36,069    356,840    1,109,748 
Trading tools and subscriptions   190,640    126,478    1,390    24,852    343,360 
Operating costs and expenses   1,080,854    9,738,970    1,436,222    1,351,394    13,607,440 
Operating income (loss)  $177,420   $434,274   $(5,009)  $(1,351,394)  $(734,691)
                          
Capital expenditures  $107,589   $22,798   $172,601   $20,245   $323,233 

 

 

 46 
 

 

Information on segments at September 30, 2015 is as follows:

 

   Wholesale
Trading
   Retail
Energy
Services
   Diversified Investments   Corporate, Net of Eliminations   Consolidated Total 
At September 30, 2015                         
Identifiable Assets                         
Cash - unrestricted  $425,193   $800,444   $349,818   $770,669   $2,346,124 
Cash in trading accounts   6,994,335    1,927,139            8,921,474 
Accounts receivable - trade   42,099    4,576,373    1,554,899    37,382    6,210,753 
Costs in excess of billings           27,034        27,034 
Marketable securities               389,974    389,974 
Notes receivable, net of deferred gain           760,504        760,504 
Prepaid expenses and other assets   12,378    77,649    50,900    186,329    327,256 
Total current assets   7,474,005    7,381,605    2,743,155    1,384,354    18,983,119 
                          
Property, equipment, and furniture, net   142,061    117,533    407,170    477,814    1,144,578 
Intangible assets, net       44,261    425,000        469,261 
Deferred financing costs, net       18,229        361,913    380,142 
Cash - restricted           1,319,371        1,319,371 
Land held for development           2,387,079        2,387,079 
Notes receivable, net of deferred gain           2,545,412        2,545,412 
Investment in convertible notes           1,718,631        1,718,631 
Goodwill           1,555,277        1,555,277 
Other assets           19,431        19,431 
Total assets  $7,616,066   $7,561,628    13,120,526   $2,224,081    30,522,301 
                          
Identifiable Liabilities and Equity                         
Current portion of:                         
Revolver  $   $2,663,637   $312,878   $   $2,976,515 
Senior notes           1,213,991        1,213,991 
Subordinated notes               9,422,406    9,422,406 
Accounts payable - trade  291,577    1,778,975    1,163,646    1,011,074    4,245,272 
Accrued expenses       1,722,442    23,064    6,580    1,752,086 
Billings in excess of costs           466,500        466,500 
Accrued compensation   873,804        62,286        936,090 
Accrued interest       26,760    11,116    1,277,597    1,315,473 
Total current liabilities   1,165,381    6,191,814    3,253,481    11,717,657    22,328,333 
                          
Senior notes           248,376       248,376 
Subordinated notes               13,257,693    13,257,693 
Total liabilities   1,165,381    6,191,814    3,501,857    24,975,350    35,834,402 
                          
Investment in subsidiaries   7,019,217    8,365,954    8,452,020    (23,837,191)    
Series A preferred equity               2,745,000    2,745,000 
Common equity   (574,925)   (6,982,060)   231,069    (1,235,617)   (9,023,671)
Accumulated other comprehensive income   6,393    (14,080)       451,541    443,854 
Non-controlling interest           1,397,718    (875,002)   522,716 
Total members' equity   6,450,685    1,369,814    9,618,669    (22,751,269)   (5,312,101)
Total liabilities and equity  $7,616,066   $7,561,628   $13,120,526   $2,224,081   $30,522,301 

 

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Information on segments for the three and nine months ended September 30, 2014 is as follows:

 

   Wholesale Trading  

Retail Energy Services 

   Diversified Investments   Corporate, Net of Eliminations   Consolidated Total 
Nine Months Ended September 30, 2014                         
Wholesale trading  $30,635,429   $2,105,208   $   $   $32,740,637 
Retail energy services       8,115,008            8,115,008 
Revenues, net   30,635,429    10,220,216            40,855,645 
                          
Cost of retail electricity sold       8,896,838            8,896,838 
Retail sales and marketing       192,017            192,017 
Compensation and benefits   14,408,864    273,030        1,167,182    15,849,013 
Professional fees   679,747    700,579    2,200    734,358    2,116,884 
Other general and administrative   6,016,006    904,408    71,160    (1,873,131)   5,118,443 
Trading tools and subscriptions   669,851    300,581    2,223    32,471    1,005,126 
Operating costs and expenses   21,774,405    11,267,453    75,583    60,880    33,178,321 
Operating income (loss)  $8,861,024   $(1,047,237)  $(75,583)  $(60,880)  $7,677,324 
                          
Capital expenditures  $15,218   $720,635   $89,009   $121,374   $946,236 

 

Three Months Ended September 30, 2014                         
Wholesale trading  $1,359,522   $54,730   $   $   $1,414,252 
Retail energy services       2,988,460            2,988,460 
Revenues, net   1,359,522    3,043,190            4,402,712 
                          
Cost of retail electricity sold       2,629,531            2,629,531 
Retail sales and marketing       40,622            40,622 
Compensation and benefits   1,070,568    106,581        378,713    1,555,862 
Professional fees   615,761    205,677    2,200    165,060    988,698 
Other general and administrative   3,681,315    301,361    11,605    (543,709)   3,450,572 
Trading tools and subscriptions   261,937    108,705    755    4,308    375,705 
Operating costs and expenses   5,629,581    3,392,477    14,560    4,372    9,040,990 
Operating income (loss)  $(4,270,059)  $(349,287)  $(14,560)  $(4,372)  $(4,638,278)
                          
Capital expenditures  $   $34,014   $32,504   $29,884   $96,402 

 

 

21. Subsequent Events

 

From October 1 to November 13, 2015, the Company sold additional Subordinated Notes totaling $1,468,574 with a weighted average term of 30.2 months and bearing a weighted average interest rate of 15.27%.

 

On November 12, 2015, the Company’s New Registration Statement was declared effective by the SEC and the Distribution was declared and executed on November 13, 2015, with an effective date as of November 1, 2015 for accounting and tax purposes.

 

The Company has evaluated subsequent events occurring through the date that the financial statements were issued.

 

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Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion should be read in conjunction with our consolidated financial statements, notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from our 2014 Form 10-K, and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-Q under the heading “Forward-Looking Statements” located on page 9, “Item 1A – Risk Factors” of our 2014 Form 10-K, and the “Risk Factors” section beginning on page 10 of our 2012 Form S-1.

 

The risks and uncertainties described in this Form 10-Q, our 2014 Form 10-K, and our Form S-1 are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition, or results of operations could suffer if the risks set forth are realized.

 

Industry Background

 

Electric power in commercial quantities, unlike other energy commodities such as coal or natural gas, cannot be stored - the supply must be produced or generated exactly when used or demanded by customers. Further, the laws of physics dictate that power flows within a network along the lines of least resistance, not necessarily where we may want it to go. These facts, coupled with the necessity of electricity in modern life, have obvious implications for market structures and regulations.

 

Overall, according to EIA data for 2013 (the most recent year for which full data is available), the U.S. electric power industry generated and sold 3,725 TWh at retail (up 0.8% from 2012) for a little more than $375.7 billion (up 3.3%) to over 146.4 million residential, commercial, industrial, and transportation customers (up 0.5%). In 2013, the average U.S. retail electricity price was 10.09¢/kWh - residential customers paid 12.13¢/kWh, commercial users paid 10.31¢/kWh, and industrial and transportation consumers paid 6.90¢/kWh.

 

Today, the industry includes any entity producing, selling, or distributing electricity. As of the end of 2013, according to the EIA, participants numbered about 2,800 and included investor-owned, publicly-owned, cooperative, and federal utilities and non-utility power producers. Power marketers and retail energy providers do not own any generation but buy and sell in wholesale and retail markets. Finally, participants in wholesale power markets include banks, hedge funds, private equity firms, and trading houses.

 

The investor-owned portion of the industry, including utilities, retail energy providers, and non-utility generators, constitutes over 70% of the industry’s revenues, unit sales, and customers. According to the Edison Electric Institute, a trade group representing the largest investor-owned utilities, in 2013, total energy operating revenues of shareholder-owned electric companies were $356.5 billion. As of December 31, 2013, consolidated holding company-level assets of these entities were $1.292 trillion, and of these assets, $791.8 billion were net property in service. As of the same date, the total market capitalization of U.S. shareholder-owned electric companies was $504.4 billion.

 

Since the passage of the Public Utilities Regulatory Policy Act of 1978, the industry has been undergoing a massive restructuring process that has had a particular impact on investor-owned utilities. PURPA stimulated development of renewable energy sources and co-generation facilities and laid the groundwork for deregulation and competition by opening wholesale power markets to non-utility producers of electricity for the first time.

 

 49 
 

 

Since PURPA, the nation has moved from a system of vertically integrated monopolies providing retail service at state-determined, cost-based rates to one where the ownership of generation assets is no longer regulated and the majority of the nation’s bulk power systems are operated under the supervision of the Federal Energy Regulatory Commission, an independent agency within the DOE. Furthermore, while some states have restructured their markets such that individual consumers are allowed to choose their electricity supplier, most state public utility commissions continue to regulate their utilities under the traditional cost-based framework.

 

Electricity Prices

 

Today, wholesale prices are subject to a federal regulatory framework focused on ensuring fair competition and reliability of supply. At the state level, under the traditional system which most states continue to employ, a vertically integrated utility is responsible for serving all consumers in a defined territory and customers are obligated to pay the regulated rate for their class of service. However, in a state with a restructured or “deregulated” market, i.e., one with retail choice, the generation, transmission, distribution, and retail marketing functions of the business are legally separated and the pricing of energy and delivery services are unbundled.

 

Wholesale electricity prices are driven by supply and demand and actually change minute-by-minute. Near term demand is largely affected by the weather and consumer behavior while supply is driven by plant availability and fuel prices, particularly for natural gas as it is the fuel of choice for marginal generation requirements. In the longer term, retail electricity prices reflect supply-side factors such as fuel prices and availability, generation technologies, plant and line construction and maintenance costs, and capital costs. Demand-side factors include population growth, economic activity, and energy efficiency. Governmental policies and regulations with respect to energy and the environment affect both the supply of, and demand for, electricity.

 

Wholesale prices are typically quoted as “on-peak”, “off-peak”, or “flat”, and in dollars per megawatt-hour ($/MWh). Peak hours are generally the 16 hours ending 0800 (8:00 am) to 2300 (11:00 pm) on weekdays, except for the NERC holidays of New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. Off-peak periods are all NERC holidays and weekend hours plus the 8 weekday hours from the hour ending at 2400 (midnight) until the hour ending at 0700 (7:00 am). Each month in a calendar year has a different number of on- and off- peak hours, consequently, the flat price for a given month takes this into account. The flat price for a day is simply the average of the 24 hourly prices. Retail prices are quoted in cents per kilowatt-hour (¢/kWh).

 

Wholesale Electricity Markets

 

After PURPA, the Energy Policy Act of 1992 was the next major legislative step towards full deregulation of wholesale power markets. In 1996, FERC issued Orders 888 and 889, which allowed for energy to be scheduled across multiple power systems, and in 1999, FERC issued Order 2000 calling for electric utilities to form RTOs or ISOs to operate the nation’s bulk power system. The intended benefits of ISOs include eliminating discriminatory access to transmission for all generators, improving operating efficiency, and increasing system reliability. ISOs are typically not-for-profit entities using governance models developed by FERC. To date, seven ISOs have been formed in the U.S. In the parts of the country where ISOs have not been established, including the southeast, southwest and northwest, active wholesale markets are still present, although they operate with different structures.

 

 50 
 

 

In addition to controlling the physical flow of power within its area of responsibility via direction to generators operating within the ISO’s footprint, many ISOs also operate wholesale markets for real-time and day-ahead energy, as well as for generating capacity and ancillary services required to ensure system reliability.

 

In general, the Company’s trading activities are characterized by the acquisition of electricity or other energy-related commodities at a given location such as a node or hub and its delivery to another. Financial transactions settle in cash in an amount equal to the difference between the purchase and sale prices, while physical transactions are settled by the delivery of the commodity. In general, financial contracts offered by ISOs such as INCs, DECs, and UTCs are also known as “virtual” trades, are outstanding overnight, and settle the next day. In addition, ISOs may also offer longer term financial contracts generally known as FTRs. On very rare occasions, our wholesale segment may also trade physical electricity between ISOs, buying in one and selling in another. In any case, the ISO serves as the counter-party and central clearinghouse for all trades.

 

 

 

In addition to the markets operated by the ISOs, derivative contracts such as swaps, options, and futures keyed to a wholesale electricity price are traded over-the-counter and on regulated exchanges, including ICE, NGX, and CME. Derivative contracts are available for many terms and pricing points and always settle in cash with profit or loss determined by price movements in the underlying commodity, whether it be electricity or another energy commodity such as natural gas or crude oil.

 

 51 
 

 

Retail Electricity Markets

 

Historically, at the state level, electricity was a regulated market, where vertically-integrated utilities owned all or a major part of the bulk power and distribution infrastructure and were responsible for generating electricity or buying it from other producers and distributing it to homes and businesses. Regulated utilities are responsible for serving all consumers in their defined territory and customers are obligated to pay the regulated rate for their class of service. Neither provider nor consumer has a choice about who they do business with.

 

In the 1990s, many states, particularly those in the Northeast and California where retail prices were historically among the highest in the country, began restructuring their electric power industries in an effort to bring the benefits of competition to retail customers. This new regulatory approach centered on deregulation of generation and retail marketing while continuing the traditional cost-of-service plan for transmission and distribution. The regulated portions of formerly vertically-integrated utilities, now generally known as electric distribution companies (“EDCs”) or local distribution companies (“LDCs”) are responsible for delivering power, billing consumers, and resolving any service issues, but customers can shop around and buy power from any licensed supplier or broker doing business in the state, hence “retail choice”.

 

Restructuring created new business opportunities in an established industry. In general, there are two types of non-utility businesses participating in the deregulated retail energy marketing function in the U.S. today – “brokers” and “suppliers” – but each state licenses these businesses in a different way. For example, not every jurisdiction makes a broker/supplier distinction and some divide licenses based on potential customer categories such as “residential” or “non-residential” while other states divide their markets based on historical utility service territories and license an entity to only provide services in particular areas. Overall, as of January 2014, there were over 700 of these licensed retail energy businesses in the U.S.

 

Brokers, also known as “aggregators”, negotiate supply agreements between retail customers and wholesale suppliers. Brokers collect commissions from the supplier that wins a particular piece of business. Brokers do not bill customers directly and never take title to energy; they work for the customer. Their major expense is signing up new customers. As a result, brokers generally have relatively limited margins but high quality cash flows and comparatively small balance sheets.

 

“Suppliers” are also known as retail energy providers (“REPs”), energy service companies (“ESCOs”), competitive energy providers (“CEPs”), or the like depending upon the state, are also licensed to deal with retail customers. They have up-stream supply arrangements which may include purchasing from an ISO like PJM or NYISO or bilaterally from large integrated energy companies or independent power producers. In contrast to brokers, suppliers potentially have higher margins on the energy sold but require larger amounts of capital to acquire energy and carry receivables and payables for some period of time.

 

 52 
 

 

Today, 16 years after Massachusetts and Rhode Island became the first states to effectively implement choice in 1998, 20 jurisdictions have some form of choice. We define these forms of retail choice as follows:

 

Type 1 All residential, commercial, and industrial customers may choose their energy provider. While this applies primarily in areas served by investor-owned utilities, in certain jurisdictions, customers of specific cooperatives and public utilities may also have choice but these instances are rare;

 

Type 2 A limited number of residential customers have choice and the choice of non-residential customers is capped, usually at a specific number of megawatt-hours per year;

 

Type 3 No residential customers have choice and the choice of non-residential customers is capped; and

 

Type 4 No residential customers have choice and the number of non-residential customers with choice is limited.

 

In addition, we define Type 0 jurisdictions as those in which no retail customers of any class have choice.

 

Overall, we believe that choice is proving to be a boon for consumers. According to an analysis of data from the EIA, between 2001 and 2013, retail rates for all customer sectors in states with restructured retail markets increased by only 21.0% compared with a 35.1% increase in states that rely on regulated utilities.

 

In the 14 areas where all rate classes had choice during 2013, according to EIA data, 25.58 million residential and 3.14 million non-residential customers were eligible to choose their supplier. Of these totals, 11.15 million residential (43.6%) and 1.91 million non-residential (61.2%) customers purchased over 559 TWh from competitive suppliers.

 

 

 

 53 
 

 

Unbundling of consumer electric bills in restructured markets made many aware for the first time exactly what they were paying for. In general, the bills of retail electricity customers include numerous costs and charges that can be classified into three major categories – generation costs, delivery charges, and governmental policy costs, such as societal benefits charges such as universal service, lifeline service, and energy efficiency programs, and sales and use taxes.

 

According to analysis of EIA data for states with restructured markets, on average between 2001 and 2013 (the latest year for which information is available) energy and delivery costs accounted for about 66.5% and 33.5%, respectively, of the average retail electricity price. Of course, these percentages fluctuate from year to year and state to state, primarily due to wholesale energy market conditions, weather, and state rules.

 

Company Overview

 

The following discussion should be read in conjunction with our consolidated financial statements, notes to those statements, and the other financial information appearing in this report. The risks and uncertainties described are not the only ones facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition, or results of operations could suffer if the risks set forth are realized.

 

The Restructuring

 

As shown by the chart below, prior to the start of the Restructuring, the Company’s name was Twin Cities Power Holdings and its active first tier subsidiaries consisted of Apollo, TCP, CTG, Cygnus, REH, and Cyclone, each of which is a Minnesota limited liability company.

 

Through these wholly-owned subsidiaries, we trade virtual electricity and energy derivative contracts in North American wholesale markets, provide electricity supply services to retail customers in certain states that permit retail choice, and engage in certain investment and real estate development activities. Consequently, we have three major business segments used to measure our activity – wholesale trading, retail energy services, and diversified investments.

 

 

Key to Chart

Orange - Holding or Services

Yellow – Wholesale Trading

Blue – Retail Energy

Gray – Diversified Investments

 

 54 
 

 

Since mid-2014, the Board of Governors has been considering ways to better position the business to access the public equity markets. Ultimately, the Board concluded that the Company’s regulatory exposure and earnings volatility, particularly that related to the wholesale trading businesses, needed to be substantially reduced or eliminated in order for such efforts to be successful. This planning took on additional urgency after the commencement by FERC on August 29, 2014 of a regulatory action that may ultimately result in the retroactive imposition of new fees - in still to be determined amounts - on trades in PJM’s UTC product which is actively traded by TCP and its SUM subsidiary. Since the announcement, UTC trading volume has decreased substantially and a number of companies have exited the market.

 

Consequently, on May 27, 2015, the Board approved a plan to restructure the Company with the goals of closing the sale of TCP, spinning out the remaining legacy businesses as defined below, and recasting the Company solely as a retail energy and financial services business.

 

To these ends, on June 1, 2015, the Company sold 100% of the outstanding equity interests of TCP and SUM to Angell, partially accomplishing its goals of reducing regulatory exposure and earnings volatility. After closing, Angell decided that it no longer wanted to operate the Lakeville office of TCP and offered the Company the opportunity to re-acquire the operation in exchange for a reduction of the purchase price. Consequently, an amendment to the Purchase Agreement, effective September 1, 2015, was executed and both the purchase price and note balance were reduced.

 

In addition to the sale of TCP, during the spring and summer of 2015 the Company created new entities to facilitate the restructuring. Enterprises was created to serve as a holding company for the Company’s legacy businesses including: (a) the remaining wholesale energy trading operations (CTG and CEF); (b) the retail energy businesses operated by REH; (c) the investments in real estate and private companies; and (d) certain other assets including the Angell note and the restricted cash pledged to a Canadian court in connection with the Company’s ex-employee litigation. Aspirity Financial was formed to provide energy-related financial services to companies and households and as part of the restructuring, lent Enterprises $22.2 million in the form of a Term Loan maturing December 30, 2019. Although initially an intercompany relationship and eliminated in consolidation, the loan is constructed on an arm’s length basis and will survive the “Distribution” as defined below. In addition, to signal to the market the change in the Company's focus, we changed our name from “Twin Cities Power Holdings, LLC” to “Aspirity Holdings LLC”, effective July 14, 2015.

 

Finally, the Aspirity Energy entities were organized to develop a new retail energy business. AENE will serve customers in the ISONE and NYISO footprints, AEMS will serve those in PJM and MISO, and AES will serve those in ERCOT. We have begun the process of becoming licensed in all 14 jurisdictions that allow choice for all retail customers. We expect most of our licensing processes to be completed by mid-2016 and that we will be able to offer electricity service to consumers in certain areas beginning early in the first quarter of 2016.

 

The last major step in the restructuring is the distribution of 100% of the equity interests of Enterprises to the Company’s common equity owners, thus completing the legal separation of the legacy businesses from the Aspirity companies (the “Distribution”). Declaration and execution of the Distribution is subject to two major conditions precedent:

·Receipt of approval of the holders of a majority by principal amount of the Company’s outstanding Subordinated Notes. This was condition was satisfied on June 26, 2015.
·Declaration of effectiveness of the Company’s New Registration Statement on Form S-1 regarding the sale of up to $75 million of Notes which was filed on May 8, 2015. This occurred on November 13, 2015.

 

 55 
 

 

The chart below reflects the organizational structure of the Company immediately following the internal reorganization but before the Distribution.

 

 

Key to Chart

Orange - Holding or Services

Yellow – Wholesale Trading

Blue – Retail Energy

Green - Financial Services

Gray – Diversified Investments

 

Our anticipated organizational structure following the Distribution is presented below.

 

 

Key to Chart

Orange - Holding or Services

Blue – Retail Energy

Green - Financial Services

 

 56 
 

 

After the Distribution, executive management of the Company will change. Mr. Krieger will resign his positions as President and Chief Executive Officer and become Chairman of the Board. Keith W. Sperbeck, currently Vice President of Operations and Secretary, and Stephanie E. Staska, currently Vice President - Risk Management and Chief Risk Officer, will resign their positions as named executive officers of Aspirity and will assume comparable roles at Enterprises.

 

Mark A. Cohn, Scott C. Lutz, and Jeremy E. Schupp will resign their positions with Apollo and become Aspirity’s President and Chief Executive Officer, Vice President and Chief Marketing Officer, and Vice President and Chief Operating Officer, respectively, and Wiley H. Sharp will remain as Vice President and Chief Financial Officer. Messrs. Cohn, Lutz, Schupp, and Sharp will hold no offices at Enterprises or any of its subsidiaries.

 

After the Distribution, our equity capitalization and ownership will change as shown by the table below. We will have one class of preferred equity outstanding, the Series A, and two classes of common membership, Class A and Class B. The Class A units will incorporate both financial and governance rights while the Class B units will include governance rights only. The Class B units will convert automatically into Class A units on a one-for-one basis when the Company achieves profitability and upon certain other conditions. 

 

   Preferred   Common 
   Pre- & Post-Distribution   Pre-Distribution   Post-Distribution 
                   Units   Percents 
   Series
A
Units
   Pct of type   Units   Pct of type   Class
A
Units
   Class
B
Units
   Total   Class
A
Units
   Class
B
Units
   Total 
Timothy S. Krieger   496    100.00%   4,935    99.50%   4,960        4,960    100.00%   0.00%   44.99%
Summer Enterprises, LLC       0.00%   25    0.50%               0.00%   0.00%   0.00%
Subtotal   496    100.00%   4,960    100.00%   4,960        4,960    100.00%   0.00%   44.99%
                                                   
Mark A. Cohn       0.00%       0.00%       1,654    1,654    0.00%   27.28%   15.00%
Wiley H. Sharp III       0.00%       0.00%       1,654    1,654    0.00%   27.28%   15.00%
Keith W. Sperbeck       0.00%       0.00%       1,654    1,654    0.00%   27.28%   15.00%
Scott C. Lutz (1)       0.00%       0.00%       551    551    0.00%   9.09%   5.00%
Jeremy E. Schupp (1)       0.00%       0.00%       551    551    0.00%   9.09%   5.00%
Subtotal       0.00%       0.00%       6,064    6,064    0.00%   100.00%   55.01%
Total   496    100.00%   4,960    100.00%   4,960    6,064    11,024    100.00%   100.00%   100.00%

 

 

1 - The Class B units of the 5.00% holders will vest over three years provided they remain employed by the Company

 

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Summary Pro Forma Financial Information

 

Condensed pro forma financial information showing the effects of the restructuring and Distribution are presented below. This information was derived from the Company’s historical consolidated financial statements and is furnished for informational purposes only. It does not purport to reflect the Company’s financial position and results of operations had the Distribution occurred on the dates indicated.

 

Further, these financial statements are not necessarily indicative of the Company’s future financial position and future results of operations and should be read in conjunction with the historical financial statements of the Company included in this report for the nine months ended September 30, 2015.

 

The pro forma balance sheet data assumes the Distribution occurred September 30, 2015, while the statement of operations data for the nine months ended September 30, 2015 assumes the Distribution occurred on January 1, 2015.

 

Our historical financial statement data, presented in column A, was adjusted, as presented in Column B, to reflect the Distribution of the equity interests of Enterprises to our members. Enterprises directly or indirectly owned virtually all of our legacy businesses. Column C reflects Aspirity on an unconsolidated basis.

 

Following the Distribution, we have determined that we must consolidate Enterprises as a VIE in which we have a non-controlling interest. An assessment of the relationship between the Company and Enterprises following the Distribution was performed because Timothy Krieger is a related party of both Aspirity and Enterprises, and because the entities have an ongoing business relationship resulting from the Term Loan. Aspirity holds a variable interest in Enterprises in the form of the Term Loan, making Enterprises a VIE. Following the Distribution, the Company will be the primary beneficiary of the VIE and will consolidate Enterprises.

 

While the Company will include the assets and net income of Enterprises in its consolidated financial statements, the Company does not have rights to those assets other than pursuant to its rights under the Term Loan. Consequently, we have made adjustments, presented in column D, to re-consolidate Enterprises with Aspirity on a pro forma basis as of September 30, 2015 as presented in Column E. See “Critical Accounting Policies-- Variable Interest Entities - Principles of Consolidation”.

 

 58 
 

 

Aspirity Holdings LLC formerly known as Twin Cities Power Holdings, LLC

Summary Pro Forma Financial Information

 

   At and For Nine Months Ended September 30, 2015 
   Historical   Pro Forma (1) 
   Aspirity
Holdings
Consolidated
(A)
   Krieger
Enterprises
(2)
(B)
   Aspirity
Holdings
(C)
   Adjustments
(D)
   Aspirity
Holdings
Re-Consolidated
(3)
(E =B+C+D)
 
Balance Sheet Data                         
Assets                         
Cash - unrestricted  $2,346,124   $1,771,220   $574,904   $   $2,346,124 
Cash in trading accounts   8,921,474    8,921,474            8,921,474 
Accounts receivable - trade   6,210,753    6,210,753            6,210,753 
Costs in excess of billings..   27,034    27,034            27,034 
Marketable securities   389,974        389,974        389,974 
Note receivable, net - current portion   760,504    760,504            760,504 
Note receivable - related party (4)           4,716,418    (4,716,418)    
Prepaid expenses & other   327,256    183,213    144,043        327,256 
Total current assets   18,983,119    17,874,198    5,825,339    (4,716,418)   18,983,119 
                          
Equipment and furniture, net   1,144,578    1,121,178    23,400        1,144,578 
Other assets, net   10,394,604    10,032,691    361,913        10,394,604 
Term Loan (5)           21,142,031    (21,142,031)    
Total assets  $30,522,301   $29,028,067   $27,352,683   $(25,858,449)  $30,522,301 
                          
Liabilities and Members' Equity                         
Accounts payable and accrued expenses  $8,248,921   $6,167,879   $2,081,042   $   $8,248,921 
Billings in excess of costs   466,500    466,500            466,500 
Note payable - related party (4)       4,716,418        (4,716,418)    
Revolvers   2,976,515    2,976,515            2,976,515 
Senior notes   1,462,367    1,462,367            1,462,367 
Term Loan (5)       21,142,031        (21,142,031)    
Renewable unsecured subordinated notes   22,680,099        22,680,099        22,680,099 
Total liabilities   35,834,402    36,931,710    24,761,141    (25,858,449)   35,834,402 
                          
Series A preferred equity   2,745,000        2,745,000        2,745,000 
Common equity   (9,023,671)   (9,023,671)           (9,023,671)
Other comprehensive income   443,854    597,312    (153,458)       443,854 
Non-controlling interest   522,716    522,716            522,716 
Total members' equity (deficit) attributable to:                         
Controlling interests (6)   (5,834,817)   (8,426,359)   2,591,542        (5,834,817)
Non-controlling interests in consolidated VIE (6)   522,716    522,716            522,716 
Total members' equity   (5,312,101)   (7,903,643)   2,591,542        (5,312,101)
Total liabilities and members' equity  $30,522,301   $29,028,067   $27,352,683   $(25,858,449)  $30,522,301 
                          
Statement of Operations Data                         
Total revenue, net  $38,213,673   $38,213,673   $   $   $38,213,673 
                         
Costs and expenses   40,067,843    37,410,944    2,656,899        40,067,843 
Expense reimbursement       1,543,924    (1,543,924)        
Total costs and expenses   40,067,843    38,954,868    1,112,975        40,067,843 
Operating income (loss)   (1,854,170)   (741,195)   (1,112,975)       (1,854,170)
                          
Interest expense (4)   (2,677,700)   (2,677,700)   (1,155,494)   1,155,494    (2,677,700)
Interest income (4)   538,802    538,802    1,155,494    (1,155,494)   538,802 
Other income (expense)   1,246,424    1,246,424            1,246,424 
Other income (expense), net   (892,474)   (892,474)           (892,474)
Net income (loss)   (2,746,644)   (1,633,669)   (1,112,975)       (2,746,644)
Net income (loss) attributable to:                         
Controlling interests   (2,746,644)   (1,633,669)   (1,112,975)       (2,746,644)
Non-controlling interest in consolidated VIE   60,617        60,617        60,617 
                          
Distributions - preferred   (411,804)       (411,804)       (411,804)
Net income (loss) attributable to common  $(3,097,831)  $(1,633,669)  $(1,464,162)  $   $(3,097,831)
Comprehensive income (loss)  $(2,388,922)  $(1,111,373)  $(1,277,549)  $   $(2,388,922)

 

 

 59 
 

 

Notes

 

1 - Balance sheet data assumes the Distribution occurred on June 30, 2015. Operating statement data assumes the Distribution occurred on January 1, 2015.

2 - Adjustment to record the Distribution of Enterprises. Post-Distribution, Enterprises will be accounted for as a variable interest entity ("VIE") of Aspirity.

3 - Reflects Aspirity's re-consolidation of Enterprises as a VIE including the elimination of the Term Loan.

4 - Reflects due to/due from amounts related to related to the Distribution.

5 - Reflects the Term Loan and the associated interest expense and income between Enterprises and Aspirity. The Term Loan is the variable interest in Enterprises held by Aspirity.

6 - All balances in common equity accounts were assigned to Enterprises while all balances in preferred equity accounts were retained by Aspirity, leaving Aspirity’s common equity accounts with zero balances as of the Distribution Date.

 

Business Plans

 

Much of the discussion that follows focuses on our operations prior to the Distribution. After the Distribution, our financial condition and operations will be significantly different from prior periods because we will have disposed of all of our legacy businesses via the distribution of the equity interests of Enterprises and will have limited operations and assets.

 

As of September 30, 2015, Aspirity had 37 employees, including 32 at Enterprises. As of November 12, 2015 following the Distribution, Aspirity had 9 employees and is engaged in extensive hiring efforts to build staff. Until we are able to generate revenue from our new operations, our cash flows will be derived almost entirely from payments we receive from Enterprises on the Term Loan and the sale of Notes. In addition to building the Aspirity Energy business, we may also decide to lend additional funds to Enterprises, as well as other companies in the energy sector, an industry in which we have significant experience.

 

Operations Prior to the Distribution

 

Wholesale Trading

 

In general, wholesale trading activities are characterized by the acquisition of electricity or other energy-related commodities at a given location and its delivery to another. ISO-traded financial contracts such as INCs, DECs, and UTCs are also known as virtual trades, are outstanding overnight, and settle the next day in cash in an amount equal to the difference between the purchase and sale prices. Physical transactions are settled by the delivery of the commodity. The Company also trades electricity and other energy derivatives on ICE, NGX, and CME and may hold an open interest in these contracts overnight or longer. On very rare occasions, the Company may also trade electricity between markets, buying in one and selling in another.

 

For the three and nine months ended September 30, 2015 and 2014, financial and virtual electricity represented 100% of our total trading volume in FERC-regulated markets, that is, we traded no physical power during these periods in our wholesale segment.

 

Following the Distribution, the Company will no longer operate a wholesale trading segment.

 

Retail Energy Services

 

On June 29, 2012, we acquired certain assets and the business of a small retail energy supplier serving residential and small commercial markets in Connecticut, and beginning on July 1, 2012, we began selling electricity to retail accounts. During late 2012 and early 2013, we applied for retail electricity supplier licenses for the states of Massachusetts, New Hampshire, and Rhode Island which were issued on various dates in 2013. On January 2, 2014, we acquired a retail energy business licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio.

 

The eight states in which REH is licensed incorporate the service territories of 33 investor-owned electric utilities. As of September 30, 2015, we were actively marketing services in 27 of these service areas.

 

Following the Distribution, we will no longer own REH and are not presently operating as a retail energy supplier. However, we intend to compete in this business as soon as Aspirity Energy has received the necessary licenses and established the necessary relationships with utilities and power suppliers.

 

 60 
 

 

Diversified Investments

 

On October 23, 2013, we formed Cyclone as a wholly-owned subsidiary to take advantage of certain perceived investment opportunities present in the residential real estate market. Specifically, we acquire and intend to develop land for resale, either as improved sites for construction of single- and multi-family homes or as completed dwellings. At various dates during 2014, we acquired certain privately placed securities for long term investment purposes and beginning in the second quarter of 2015, we began selling management services to third parties. On September 1, 2015, Enterprises purchased its controlling interest in Noble and thereby began providing construction services.

 

Following the Distribution, we will no longer own Cyclone nor do we intend to engage in these types of activities in the future.

 

Derivative Instruments

 

In our wholesale operations, we use derivative contracts for trading purposes, seeking to profit from perceived opportunities driven by expected changes in market prices. These contracts include exchange-traded instruments such as futures contracts, which are Level 1 instruments in the fair value hierarchy as well as FTRs available through certain FERC-regulated markets, which we consider to be Level 3 instruments as they are not regularly quoted.

 

We acquire the majority of our FTRs in auctions conducted by ISOs, including MISO, PJM, NYISO, ISO-NE, and ERCOT. We initially record these FTRs at the auction price less the obligation due to the ISO, typically zero, and subsequently adjust the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Like the other derivatives we trade, changes in the fair value of FTRs are included in our wholesale trading revenues.

 

In our retail business, we are exposed to volatility in the cost of energy acquired for sale to customers, and as a result, we use derivatives to hedge or reduce this variability. Our retail operations follow GAAP guidance that permits “hedge accounting”. To qualify for hedge accounting, the relationship between the “hedged item” - say power purchases for a given delivery zone - and a derivative used as a “hedging instrument” - say, a swap contract for future delivery of electricity at a related hub - must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis. For these derivatives “designated” as cash flow hedges, the effective portion of any change in the hedging instrument’s fair value is recorded as other comprehensive income and deferred until the change in value of the hedged item is recognized in earnings. Our risk management policies also permit the use of undesignated derivatives which we refer to as “economic hedges”. For an undesignated economic hedge, all changes in the derivative financial instrument’s fair value are recognized currently in revenues.

 

 61 
 

 

The table below details our open derivative contracts held for trading purposes and as undesignated, economic hedges and as designated cash flow hedges by our retail segment as of September 30, 2015 and December 31, 2014:

 

Open Derivative Contracts 
                  Fair Value 
Date, segment and
contract type
  Hub or zone  Delivery period   Final settlement   Energy
(MWh)
   Asset   Liability 
As of September 30, 2015                 
                  
Wholesale Trading                     
Electricity futures  PJM West Hub   Q4 2015    various    28,800   $3,840   $7,000 
Natural gas futures  Henry Hub   Q4 2015    various    75,000    1,950      
Electricity futures  AESO   Q4 2015    various    125,160    827,662    772,713 
Electricity futures  AESO   Q1 2016    various    2,480        24,972 
Electricity futures  AESO   Q2 2016    various    14,760    79,384    91,370 
Electricity futures  AESO   Q3 2016    various    3,720    22,252    34,317 
Subtotal                249,920    935,088    930,373 
                             
Retail Energy Services - Economic Hedges                     
Electricity futures  ISO-NE Mass Hub   Q2 2016    various    1,840    1,196      
Electricity futures  ISO-NE Mass Hub   Q3 2016    various    1,680    4,956      
Electricity futures  PJM West Hub   Q4 2015    various    6,880        50,586 
Subtotal                10,400    6,152    50,586 
                             
Retail Energy Services - Designated Cash Flow Hedges                     
Electricity futures  ISO-NE Mass Hub   Q4 2015    various    352        14,080 
Subtotal                352        14,080 
Totals                260,672   $941,240   $995,038 
                             
As of December 31, 2014                     
                             
Wholesale Trading                     
Electricity futures  PJM West Hub   daily    daily    6,400   $22,400   $ 
FTRs  MISO, NYISO, PJM   Q1 & Q2 2015    various    8,981,440    1,435,819     
Electricity futures  AESO   Q1 2015    various    80,320    785,617    286,250 
Electricity futures  AESO   Q2 2015    various    135,600    892,838    1,094,059 
Electricity futures  AESO   Q3 2015    various    78,120    601,993    783,893 
Subtotal                9,281,880    3,738,667    2,164,202 
                             
Retail Energy Services - Economic Hedges                     
Electricity futures  ISO-NE Mass Hub; PJM West Hub   Q1 2015    various    3,715        44,373 
Electricity futures  PJM West Hub   Q2 2015    various    14,280        107,120 
Natural gas futures  Henry Hub   Q2 2015    various    155,000    14,803     
Electricity futures  PJM West Hub   Q3 2015    various    16,240    31,926    65,196 
Natural gas futures  Henry Hub   Q3 2015    various    77,500    1,085     
Electricity futures  PJM West Hub   Q4 2015    various    21,285        175,971 
Subtotal                288,020    47,814    392,660 
                             
Retail Energy Services - Designated Cash Flow Hedges                     
Electricity futures  ISO-NE Mass Hub   Q1 2015    various    13,995        498,166 
Electricity futures  ISO-NE Mass Hub   Q2 2015    various    16,120        184,378 
Electricity futures  ISO-NE Mass Hub   Q3 2015    various    18,480    15,732    189,116 
Electricity futures  ISO-NE Mass Hub   Q4 2015    various    352        7,480 
Subtotal                48,947    15,732    879,140 
Total                9,618,847   $3,802,213   $3,436,002 

 

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Results of Operations

 

Three Months Ended September 30, 2015 and 2014

 

The following table sets forth selected financial data for the periods indicated, which has been derived from the consolidated financial statements included in this report:

 

   For The Three Months Ended Sept 30, 
Dollars in thousands  2015   2014   Increase (decrease)  
   Dollars   Percent   Dollars   Percent   Dollars   Percent 
Revenue                        
Wholesale trading, net  $1,309    10.2%  $1,414    32.1%  $(105)   -7.4%
Retail energy services   10,122    78.6%   2,989    67.9%   7,133    238.6%
Real estate sales   352    2.7%       0.0%   352    na   
Management services   375    2.9%       0.0%   375    na   
Construction services   714    5.5%       0.0%   714    na   
Net revenue   12,872    100.0%   4,403    100.0%   8,469    188.1%
                               
Operating costs & expenses                              
Cost of retail electricity sold   8,032    63.3%   2,629    59.7%   5,403    205.5%
Cost of real estate sold   297    2.3%       0.0%   297    na   
Cost of construction services   620    4.9%       0.0%   620    na   
Retail energy sales & marketing   421    3.3%   41    0.9%   380    926.8%
Compensation & benefits   1,966    15.5%   1,556    35.3%   410    26.3%
Professional fees   818    6.4%   989    22.5%   (171)   -17.3%
Other general & administrative   1,110    8.7%   3,451    78.4%   (2,341)   -67.8%
Trading tools & subscriptions   343    2.7%   376    8.4%   (33)   -8.8%
Total operating expenses   13,607    107.3%   9,042    205.4%   4,565    50.5%
                               
Operating loss   (735)   -5.7%   (4,639)   -105.4%   3,904    -84.2%
                               
Interest expense   (1,009)   -8.0%   (604)   -13.7%   (405)   67.1%
Interest income   319    2.5%   48    1.0%   271    564.6%
Gain on sale of subsidiary   672    5.3%       0.0%   672    na    
Gain (loss) on foreign currency exchange   (84)   -0.7%   (142)   -3.2%   58    -40.8%
Gain (loss) on sale of marketable securities   (15)   -0.1%   63    1.4%   (78)   -123.8%
Other income   88    0.7%   3    0.1%   85    2833.3%
Other expense, net   (29)   -0.3%   (632)   -14.4%   603    -95.4%
                               
Net income   (764)   -5.9%   (5,271)   -119.7%   4,507    -85.5%
Preferred distributions   (137)   -1.1%   (137)   -3.1%       0.0%
Net loss attributable to non-controlling interest   61    0.5%       0.0%   61    na   
                               
Net income attributable to common  $(840)   -6.5%  $(5,408)   -122.8%  $4,568    -84.5%

 

Wholesale trading revenue: In our wholesale trading business, we record revenues based upon changes in the fair values of the contracts we trade, net of costs. The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of instruments that remain open at a balance sheet date represent unrealized gains or losses. Our primary costs in generating trading revenue are compensation of our energy traders as well as the interest expense of obtaining the capital necessary to post collateral.

 

Generally, our greatest opportunities for profitable trades occur during periods of market turbulence, when the forecast for supply or demand is more likely to be inaccurate. When demand for energy is relatively stable, price variations tend to be small or non-existent. During periods of market turbulence, prices tend to be volatile, which give our traders the opportunity to take advantage of such volatility. Furthermore, our revenue is limited to some extent by the amount of collateral we have posted with a market operator or exchange.

 

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On a wholesale level, electricity prices are highly correlated with weather and the price of natural gas, particularly in our key eastern markets, where it is the marginal fuel of choice for most generation. The benchmark price to which much of our wholesale trading is keyed is PJM West Hub and volatility in this index drives many of our revenue opportunities. While our revenues generally track changes in price, other factors come into play as well, such as the size of trades we have in place in terms of megawatt-hours and whether or not we are buying or selling.

 

Market conditions during the third quarter of 2015 were characterized by normal weather, with an average temperature only 0.3° above normal (71.8°F versus 71.5°F), and cheaper than normal natural gas (down about 27% to $2.75/MCF versus the 5 year average of $3.60/MCF).

 

The third quarter of 2015 was 2% warmer than the same period in 2014, with an average temperature of 71.8°F versus 70.5°F. Heating degree-days for the U.S. in the third quarter of 2015 totaled 48 or 40% below 2014’s figure of 80 and cooling degree-days totaled 865 compared to 764 in 2014. For 2015, the Henry Hub natural gas spot price averaged $2.75/MCF, 31% below 2014’s $3.96 mark. Supplies of gas during 2015 were adequate. Weekly storage levels averaged 3,071 BCF or 20% more than 2014’s level of 2,554 and 3% higher than the 5 year average of 2,981.

 

   Three Months Ended September 30, 
               Increase (decrease) 
   Units   This year vs last year   This year vs LTA 
   2015   2014   LTA (1)   Units   Percent   Units   Percent 
U.S. Weather                                   
Heating degree-days   48    80    81    (32)   -40%   (33)   -41%
Cooling degree-days   865    764    816    101    13%   49    6%
Avg temperature (°F)   71.8°F    70.5°F    71.5°F    1.3°F    2%   0.3°F    0%
                                    
Natural Gas                                   
Henry Hub spot price ($/MCF)   2.75    3.96    3.60    (1.21)   -31%   (0.84)   -23%
Working gas in underground storage, Lower 48 states, EIA weekly estimates (BCF)   3,071    2,554    2,981    517    20%   90    3%

 

 

1 - gf"LTA" abbreviates long term average. For weather data, the 30 year period is 1984-2013 and for natural gas the 5 year period is 2009-2013.

 

The average for the day-ahead PJM West Peak price during the third quarter of 2015 was $40.32/MWh with a standard deviation of $8.97 resulting in a coefficient of variation of 22%, compared to $50.48/MWh, $7.95, and 16% for 2014. The high for the period was $72.74/MWh and the low was $27.58.

 

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As shown by the table below, price levels were generally lower but volatility was slightly higher in 2015 as compared to 2014.

 

   Three Months Ended September 30, 
PJM West Hub Peak Day Ahead          Increase (decrease) 
   2015   2014   Units   Percent 
Price ($/MWh)                    
Average   39.23    41.11    (1.88)   -5%
Maximum   102.98    65.21    37.77    58%
Minimum   24.99    30.97    (5.97)   -19%
Standard deviation   11.03    6.31    4.72    75%
Coefficient of variation (stdev ÷ avg)   28%   15%   13%   83%
                     
Daily percentage changes                    
Average   1.0%   0.1%   0.9%   668%
Maximum   87.5%   35.9%   51.6%   144%
Minimum   -43.1%   -22.0%   -21.1%   96%
Standard deviation   17.2%   10.3%   6.8%   66%
                     
Number of days                    
Up 10% or more   18    11    7    64%
Between 10% up and 10% down   30    40    (10)   -25%
Down 10% or more   16    13    3    23%

 

During the third quarter of 2014, the Company settled with FERC and included $1,106,000 as a reduction of revenue that represented the disgorgement of profits and interest. During the second quarter of 2015, the Company sold TCP and SUM, thus revenue for the third quarter of 2015 declined due to less traders. Largely as a result of these factors for the three months period ended September 30, 2015, net trading revenue decreased by $105,000 or 7.4% compared to $1,414,000 for the same period in 2014.

 

Retail electricity sales: Revenue from the retail sale of electricity is recorded in the period in which customers consume the commodity, net of any applicable sales tax. Revenue applicable to electricity consumed by customers but not yet billed under the cycle billing method is estimated and accrued along with the related costs. Changes in estimates are reflected in operations in the period in which they are refined.

 

In addition to the designated hedges described below in “costs of retail electricity sold” to which hedge accounting was applied, we also used certain derivative contracts to which hedge accounting was not applied as economic hedges in our retail business to reduce our exposure to higher costs. In our segment reporting, the gain on these contracts net of any losses is reported as “wholesale trading revenue, net”.

 

For the three months ended September 30, 2015 and 2014, we recorded total revenues in our retail segment of $10,173,000 and $3,043,000, respectively. These totals consisted of retail energy sales of $10,122,000 in 2015 and $2,989,000 in 2014, up 238.7%, and wholesale trading gains of $51,000 and $55,000, respectively. 2015’s results were driven by a 138.9% increase in customers as a result of increased marketing efforts.

 

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The following table details key operating statistics for the periods indicated:

 

Key Operating Statistics  For/At Three Months Ended September 30, 
(in units unless otherwise indicated)          Increase (decrease) 
   2015   2014   Units   Percent 
Retail electricity sales ($000s)   10,122    2,988    7,134    238.8%
Wholesale trading revenue, net ($000s)   51    55    (4)   -7.3%
Total segment revenues ($000s)   10,173    3,043    7,130    234.3%
                     
Unit sales (MWh)   120,649    33,452    87,197    260.7%
Weighted average retail price (¢/kWh)   8.43    9.10    (0.66)   -7.3%
                     
Customers receiving service, end of period   34,980    14,644    20,336    138.9%

 

During the three months ended September 30, 2015, retail energy sales revenue increased principally as a result of an increase in customer count. Our customer base is a combination of residential and commercial accounts. We primarily use direct marketing strategies to acquire our customers.

 

Real estate sales: Revenues from real estate developments, if any, are recognized at the time of sale closing if all significant conditions are satisfied, including adequate down payment, reasonable assurance of collectability of any notes received, and completion of other contract requirements. Recognition of all or part of the revenue is deferred if any significant conditions are not satisfied.

 

Costs that relate directly to development projects are capitalized and allocated using the specific identification method. Land acquisition, improvements, and holding costs, including real estate taxes and interest are capitalized while a development is in progress. Interest expense, if any, is capitalized based on specific identification of notes payable issued to finance specific assets under development. Once development on a project has been completed and sales have begun, remaining inventory is recorded at the lower of cost or market. Development costs are charged to cost of sales when the related revenue is recognized or when a development is abandoned.

 

The Company recorded real estate sales of $352,000 in the third quarter of 2015.

 

Management services: During 2015, we began selling management services to third parties. For the three months ended September 30, 2015 we recorded revenue of $375,000.

 

Construction services: With the acquisition of Noble in September 2015, the Company began generating revenue from providing consulting and construction services, principally to businesses and commercial property owners. Our services including sustainability strategy consulting and integrated energy efficiency design and implementation. Total revenue for the three months ended September 30, 2015 was $714,000.

 

Cost of retail electricity sold: Our costs of electricity sold include the cost of purchased power, EDC service fees, renewable energy certificates, bad debt expense, and gains net of losses and commissions on derivative contracts used to hedge power purchase costs. Cost of sales does not include the net gain or loss on the economic hedges described above. During the third quarters of 2015 and 2014, we purchased electricity for sale to retail customers from ISOs and wholesale suppliers. We are typically required to maintain cash deposits in separate accounts to meet our wholesale energy vendors’ financial assurance requirements to purchase energy, ancillary services, and capacity which amount is included in “cash in trading accounts”.

 

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For the three months ended September 30, 2015, the Company hedged the cost of 58,080 MWh or 48.14% of the 120,649 MWh of electricity sold to its retail customers in such period using designated derivatives contracts. The comparable figures for the three months ended September 30, 2014, were 17,640 MWh or 52.8% of the 33,416 MWh of electricity sold.

 

In total, during the three months ended September 30, 2015 and 2014, we recorded costs of retail electricity sold of $8,032,000 and $2,629,000, respectively, resulting in gross income of $2,069,000 in 2015 and $337,000 in 2014. If our economic hedges were treated in the same way as that of the designated hedges, that is, with gains decreasing costs of sales and with losses increasing such, gross margins would have been $2,090,000 in 2015 and $360,000 for 2014.

 

Cost of real estate sold: The Company recorded cost of real estate sold of $297,000 in the third quarter of 2015. During the quarters ended September 30, 2015 and 2014, the Company capitalized a total of $615,000 and $32,000, respectively, of costs associated with its real estate development activities, consisting primarily of purchases of land for development and construction costs incurred.

 

Cost of construction services: Included in this expense are costs incurred related to construction service revenue. The category includes material, equipment rental, and installation labor. For the three month period ended September 30, 2015 a total of $620,000 was incurred.

 

Retail energy sales and marketing: Retail energy sales and marketing costs and expenses include off-line and on-line marketing costs related to retail customer acquisition and retention. Major off-line marketing channels may include out-bound telemarketing, direct mail, door-to-door, mass media (radio, television, print, and outdoor), and affiliates. On-line marketing channels may include paid search, affiliates, comparison shopping engines, banner or display advertising, search engine optimization, and e-mail marketing.

 

For the third quarter of 2015 we spent $421,000 in marketing compared to $41,000 in the third quarter 2014.

 

Compensation and benefits: Salaries, wages, and related costs such as employee benefits and payroll taxes consist primarily of base and incentive compensation paid to our administrative officers, energy traders, and other employees.

 

For the three months ended September 30, 2015 and 2014, salaries, wages, and related costs increased by $410,000 or 26.3% to $1,966,000 compared to $1,556,000 for the same period in 2014. Our personnel expense is directly related to the revenue we record. Although our revenue declined our compensation and benefits has increased with the need for additional executives for the reorganization of the Company.

 

Professional fees: Professional fees consist of legal expenses, audit fees, tax compliance reporting service fees, and other fees paid for outside consulting services.

 

For the third quarter 2015, professional fees decreased by $171,000 to $818,000 compared to $989,000 in the third quarter of 2014. The majority of the decrease is due to elimination of the costs of certain independent contractors.

 

Other general and administrative: Other general and administrative expenses consist of rent, depreciation, travel, outside retail customer service costs, and all other direct office support expenses.

 

 67 
 

 

For the third quarter of 2015, these costs decreased by approximately $2,341,000 to $1,110,000 compared to $3,451,000 for 2014. The decrease was primarily related to the FERC settlement which included $2,500,000 of a civil penalty that was included in other general and administrative expenses. After that consideration the costs have really increased, primarily for marketing and administrative expenses associated with the Notes Offering. We incurred $563,000 and $429,000 in marketing and administrative expenses associated during the third quarter of 2015 and 2014, respectively.

 

Trading tools and subscriptions: Trading tools and subscriptions consist primarily of amounts paid for services that provide weather reports and forecasting, electrical load forecasting, congestion analysis and other factors relative to electricity production and consumption.

 

For the three months ended September 30, 2015, trading tools and subscriptions expense decreased by $33,000 to $343,000 compared to $376,000 for the same period in 2014, primarily due to the decreased need for subscriptions due to the sale of TCP in June of 2015.

 

Other income (expense): Interest income on securities is recorded in other income and fair value is reported on the balance sheet. Securities are reviewed for possible impairment at least quarterly, or more frequently if circumstances arise which may indicate impairment.

 

Other expense, net of other income, was $29,000 for the third quarter of 2015 compared to $632,000 for the same period in 2014. Interest expense increased by $405,000 to $1,009,000 for the 2015 period compared to $604,000 for the same period in 2014, primarily due to an increase in outstanding debt. During the third quarter of 2015, the Company recognized $672,000 of gain on the sale of TCP to Angell. For the three months ended September 30, 2015, interest income increased to $319,000 compared to $48,000 for the same period in 2014, due to an increase in interest bearing assets outstanding.

 

Preferred distributions: During the third quarters of 2015 and 2014, we distributed $137,000 to our preferred unit holder.

 

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Nine Months Ended September 30, 2015 and 2014

 

The following table sets forth selected financial data for the periods indicated, which has been derived from the consolidated financial statements included in this report:

 

   For The Nine Months Ended September 30, 
Dollars in thousands  2015   2014   Increase (decrease) 
   Dollars   Percent   Dollars   Percent   Dollars   Percent 
Revenue                              
Wholesale trading, net  $13,081    34.2%  $32,741    80.1%  $(19,660)   -60.0%
Retail energy services   23,566    61.7%   8,115    19.9%   15,451    190.4%
Real estate sales   352    0.9%       0.0%   352    na   
Management services   500    1.3%       0.0%   500    na   
Construction services   714    1.9%       0.0%   714    na   
Net revenue   38,213    100.0%   40,856    100.0%   (2,643)   -6.5%
                               
Operating costs & expenses                              
Cost of retail electricity sold   20,350    53.5%   8,897    21.8%   11,453    128.7%
Cost of real estate sold   298    0.8%       0.0%   298    na   
Cost of construction services   620    1.6%       0.0%   620    na   
Retail energy sales & marketing   1,024    2.7%   192    0.5%   832    433.3%
Compensation & benefits   11,195    29.4%   15,849    38.8%   (4,654)   -29.4%
Professional fees   2,135    5.6%   2,117    5.2%   18    0.9%
Other general & administrative   3,420    9.0%   5,118    12.5%   (1,698)   -33.2%
Trading tools & subscriptions   1,025    2.7%   1,005    2.5%   20    2.0%
Total operating expenses   40,067    105.4%   33,178    81.2%   6,889    20.8%
Operating loss   (1,854)   -4.9%   7,678    18.8%   (9,532)   -124.1%
                               
Interest expense   (2,678)   -7.0%   (1,587)   -3.9%   (1,091)   68.7%
Interest income   539    1.4%   100    0.2%   439    439.0%
Gain on sale of subsidiary   672    1.8%       0.0%   672    na   
Gain (loss) on foreign currency exchange   417    1.1%   (402)   -1.0%   819    203.7%
Gain (loss) on sale of marketable securities   (13)   0.0%   66    0.2%   (79)   -119.7%
Other income   171    0.4%   6    0.0%   165    2750.0%
Other expense, net   (892)   -2.3%   (1,817)   -4.4%   925    -50.9%
Net income   (2,746)   -7.2%   5,861    14.3%   (8,607)   -146.9%
                               
Preferred distributions   (412)   -1.1%   (412)   -1.0%       0.0%
Net loss attributable to non-controlling interest   61    0.4%       0.0%   61    na   
Net income attributable to common  $(3,097)   -8.1%  $5,449    13.3%  $(8,546)   -156.8%

 

Wholesale trading revenue: Market conditions during the first nine months of 2015 were characterized by normal weather, with an average temperature of 56.9°F versus a normal of 56.9°F and cheaper than normal natural gas, down about 26% to $2.80/MCF versus the 5 year average of $3.76/MCF.

 

Heating degree-days for the U.S. in the 2015 period totaled 2,864 or 6% below 2014’s figure of 3,054 and cooling degree-days totaled 1,335 compared to 1,182 in 2014. For the first nine months of 2015, the Henry Hub natural gas spot price averaged $2.80/MCF, 39% below 2014’s $4.57 mark. Supplies of gas during 2015’s first nine months were good. Weekly storage levels averaged 2,402 BCF or 31% more than 2014’s level of 1,832 and 1% lower than the 5 year average of 2,417.

 

 

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   Nine Months Ended September 30, 
               Increase (decrease) 
   Units   This year vs last year   This year vs LTA 
   2015   2014   LTA (1)   Units   Percent   Units   Percent 
U.S. Weather                                   
Heating degree-days   2,864    3,054    2,745    (190)   -6%   119    4%
Cooling degree-days   1,335    1,182    1,227    153    13%   108    9%
Avg temperature (°F)   56.9°F    55.2°F    56.9°F    1.7°F    3%   0.0°F    0%
                                    
Natural Gas                                   
Henry Hub spot price ($/MCF)   2.80    4.57    3.76    (1.77)   -39%   (0.96)   -26%
Working gas in underground storage, Lower 48 states, EIA weekly estimates (BCF)   2,402    1,832    2,417    571    31%   (15)   -1%

 

 

1 - "LTA" abbreviates long term average. For weather data, the 30 year period is 1984-2013 and for natural gas the 5 year period is 2009-2013.

 

This return to normal market conditions showed up in decreased volatility in wholesale electricity prices as measured by the PJM West Hub peak price. The average for the day-ahead mark during the first nine months of 2015 was $43.89/MWh with a standard deviation of $22.38 resulting in a coefficient of variation of 51%, compared to $58.65/MWh, $54.81, and 93% for the comparable 2014 period. The high for 2015 year to date was $237.48/MWh, 64% lower than 2014’s comparable figure of $655.75/MWh, and the low was $27.58 or 6% lower than the prior period’s level of $26.49. As shown by the table below, price levels and volatility were generally lower in 2015 as compared to 2014.

 

   Nine Months Ended September 30, 
PJM West Hub Peak Day Ahead          Increase (decrease) 
   2015   2014   Units   Percent 
Price ($/MWh)                
Average   43.89    58.65    (14.76)   -25%
Maximum   237.48    655.75    (418.27)   -64%
Minimum   24.99    26.49    (1.49)   -6%
Standard deviation   22.38    54.81    (32.43)   -59%
Coefficient of variation (stdev ÷ avg)   51%   93%   -42%   -45%
                     
Daily percentage changes                    
Average   2.1%   2.5%   -0.5%   -19%
Maximum   209.3%   200.3%   9.0%   4%
Minimum   -63.5%   -78.1%   14.7%   -19%
Standard deviation   23.4%   25.8%   -2.4%   -9%
                     
Number of days                    
Up 10% or more   54    51    3    6%
Between 10% up and 10% down   84    90    (6)   -7%
Down 10% or more   53    50    3    6%

 

Net trading revenue for the nine months ended September 30, 2015 decreased to $13,081,000 or by 60% compared to $32,741,000 for the same period in 2014. In addition to the reduction in favorable trading opportunities and revenue caused by the return of more normal weather compared to 2014’s polar vortex, 2014’s figures also include revenues from FTR trading activity (discontinued in May 2015) and TCP and SUM (sold on June 1, 2015).

 

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Retail electricity sales: For the nine months ended September 30, 2015 and 2014, we recorded total revenues in our retail segment of $23,285,000 and $10,220,000, respectively. These totals consisted of retail energy sales of $23,566,000 in 2015 and $8,115,000 in 2014, up 190.4%, and a wholesale trading loss of $281,000 in 2015 and a gain of $2,105,000 in 2014. 2015’s results were driven by a 138.9% increase in customers as a result of increased marketing efforts.

 

The following table details key operating statistics for the periods indicated:

 

Key Operating Statistics  For/At Nine Months Ended September 30, 
(in units unless otherwise indicated)          Increase (decrease) 
   2015   2014   Units   Percent 
Retail electricity sales ($000s)   23,566    8,115    15,451    190.4%
Wholesale trading revenue, net ($000s)   (281)   2,105    (2,386)   -113.3%
Total segment revenues ($000s)   23,285    10,220    13,065    127.8%
Unit sales (MWh)   268,797    80,655    188,142    233.3%
Weighted average retail price (¢/kWh)   8.66    12.67    (4.01)   -31.6%
Customers receiving service, end of period   34,980    14,644    20,336    138.9%

 

Real estate sales: During the nine months ended September 30, 2015, the Company recorded real estate sales of $352,000.

 

Management services: For the nine months ended September 30, 2015 we recorded management services revenue of $500,000.

 

Construction services: With the acquisition of Noble in September 2015, total construction service revenue for the nine months ended September 30, 2015 was $714,000.

 

Cost of retail electricity sold: For the nine months ended September 30, 2015, the Company hedged the cost of 92,355 MWh (34.4%) of the 268,796 MWh of electricity sold to its retail customers in such period via designated derivatives. For the year, our hedges had the effect of increasing the cost of retail electricity sold by $1,700,000.

 

As shown by the Open Derivative Contracts table on page 62, as of September 30, 2015, we had designated futures contracts for 352 MWh as cash flow hedges of expected electricity purchases in the remainder of 2015. $14,080 of the net loss on the 2015 contracts was deferred and included in AOCI. These amounts are expected to be reclassified to cost of energy sold by December 31, 2015.

 

As shown by the Open Derivative Contracts table on page 62, as of December 31, 2014, we had hedged the cost of 48,947 MWh (approximately 10.5% of 2015’s expected electricity purchases for the customers receiving service from us as of that date) and $863,408 of the net loss on the effective portion of the hedge was deferred and included in AOCI. This amount is expected to be reclassified to cost of retail electricity sold by December 31, 2015.

 

Principally as a result of increases in the amount of energy used per customer, increased costs, and an increase customer count, for the nine months ended September 30, 2015, our cost of retail electricity sold, net of losses on designated hedges, increased by $11,453,000 or 128.7% to $20,350,000 compared to $8,897,000 for the same period in 2014.

 

Cost of real estate sold: During the nine months ended September 30, 2015 and 2014, the Company recorded costs of real estate sold of $298,000 and zero, respectively. Also during the respective 2015 and 2014 periods, $1,570,000 and $88,000 of costs associated with real estate development, consisting primarily of purchases of land for development and construction costs incurred, were capitalized.

 

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Cost of construction services: For the nine month period ended September 30, 2015 a total of $620,000 of construction services costs were incurred.

 

Retail energy sales and marketing: For the nine month periods ended September 30, 2015 and 2014, we spent $1,024,000 and $192,000, respectively, on retail energy sales and marketing, principally on outbound telemarketing.

 

Compensation and benefits: During the nine month periods ended September 30, 2015 and 2014, salaries, wages, and related costs decreased by $4,654,000 or 29.4% to $11,195,000, compared to $15,849,000 for the same period in 2014. A substantial portion of our personnel expense is directly related to the revenue we record, since trader compensation is tied to revenue production, this decrease in expense is in line with the decrease in revenues.

 

Professional fees: For the nine months ended September 30, 2015, professional fees increased by $18,000 to $2,135,000 compared to $2,117,000 for the 2014 comparable period, due principally to legal fees incurred in connection with the restructuring.

 

Other general and administrative: For the period ended September 30, 2015, these costs decreased by approximately $1,698,000 to $3,420,000 compared to $5,118,000 for 2014, $2,500,000 FERC penalty from 2015’s figure. Other general and administrative expenses actually increased. The increase was mainly associated with increase after considering the 2014 spending on marketing and administrative expenses associated with the Notes Offering. We incurred $1,666,000 and $992,000 in marketing and administrative expenses associated with our Notes during the nine months ended September 30, 2015, and 2014, respectively.

 

Trading tools and subscriptions: For the nine months ended September 30, 2015 and 2014, trading tools and subscription expense increased by $20,000 or 2% to $1,025,000 compared to $1,005,000 for the same period in 2014, primarily due to an increase in volumetric fees incurred for retail billing services.

 

Other income (expense): Other expense, net of other income, decreased by $925,000 to $892,000 for the nine months ended September 30, 2015 compared to $1,817,000 for the same period in 2014.

 

Interest expense increased to $2,678,000 for the 2015 year to date period compared to $1,587,000 for the same period in 2014. The increase was attributed primarily to an increase in outstanding debt to $27,619,000 as of September 30, 2015 compared to $19,288,000 outstanding as of December 31, 2014 and $16,348,000 as of September 30, 2014 compared to $10,185,000 outstanding as of December 31, 2013.

 

During the nine months ended September 30 2015, the Company recognized $672,000 of gain on the sale of TCP. Interest income increased to $539,000 from $100,000 for the nine months ended September 30, 2015 compared to the same period in 2014, primarily due to an increase in interest bearing asset balances, including the Ultra Green convertible notes, the Angell note, and the Noble revolver. The gain on foreign currency exchange was $417,000 for the nine months ended September 30, 2015 compared to a loss of $402,000 in the 2014 period.

 

Preferred distributions: During each of the nine month periods ended September 30, 2015 and 2014, we distributed $412,000 to our preferred unit holder.

 

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Liquidity, Capital Resources, and Cash Flow

 

In our wholesale trading business, we require a significant amount of cash to pledge as collateral to market operators which allows us to trade and generate revenues. With respect to our retail operation, in addition to collateral posted with ISOs that allows us to acquire power for our customers, we are also required to fund accounts receivable as well as margin requirements associated with hedges. We are generally required to pay for power every 4 days or so, while our average collection period on receivables is 40 to 45 days. As such, our capital is largely invested in trading accounts and deposits and receivables. Our capital expenditure requirements are nominal, being limited largely to computer and office equipment, software, and office furniture. Therefore, in any given reporting period, the amount of cash consumed or generated will primarily be due to changes in working capital.

 

Historically, our capital requirements have been funded by notes payable and operating profits and we are dependent on cash on hand, cash-flow positive operations, and additional financing to service our existing obligations. Should we incur significant losses from operations within a short period, we would be forced to cover such payments by reducing the balances in our trading accounts. Either of such events would have a detrimental effect on the Company.

 

We are taxed as a partnership for income tax purposes which means that we do not pay any income taxes. All of our income (or loss) for each year is allocated among holders of our common units who are then personally responsible for the tax liability associated with such income. Our Member Control Agreement provides for distributions of cash to these members based upon their respective ownership interests in the amount necessary to permit the member who is in the highest income tax bracket to pay all state and federal taxes on our net income allocated to such member.

 

The decision to make distributions other than tax distributions to holders of our common units and required distributions to holders of preferred units is at the discretion of our Board of Governors (the “Board”) and depends on various factors, including our results of operations, financial condition, capital requirements, contractual restrictions, outstanding indebtedness, investment opportunities, and other factors considered by the Board to be relevant. The indenture governing our Notes prohibits us from paying distributions to our members if there is an event of default with respect to the Notes or if payment of the distribution would result in an event of default. The indenture also prohibits our Board from declaring or paying any distributions other than tax distributions if, in the reasonable determination of the Board, the Company would have insufficient cash to meet anticipated Note redemption or repayment obligations.

 

While we believe we have sufficient cash on hand, coupled with anticipated cash generated from operating activities and the anticipated proceeds from our Notes Offering to meet our operating cash requirements for at least the next twelve months, we regularly evaluate other potential sources of capital, which may include sourcing additional financing in the form of debt in order to provide added flexibility to support our working capital needs and reduce our overall costs of borrowing. In addition, the Company currently has sufficient liquidity for its operating requirements and expects to use a portion of its available cash to finance additional retail energy expansion and acquisitions, and may also examine a variety of potential investments for its excess cash, which could include equities, real estate, and debt instruments. There can be no assurance that these investments will prove to be profitable.

 

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The following table measures our liquidity and capital resources as of the dates indicated:

 

   At         
   September 30, 2015   December 31, 2014   Increase (decrease) 
   Dollars   Percent of total assets   Dollars   Percent of total assets   Dollars   Percent 
Liquidity                              
Cash - unrestricted  $2,346    7.9%  $2,397    7.5%  $(51)   -2.1%
Cash in trading accounts   8,921    29.9%   21,100    66.4%   (12,179)   -57.7%
Accounts receivable   6,211    20.8%   2,394    7.5%   3,817    159.4%
Total liquid assets (1)   17,478    57.8%   25,891    81.6%   (8,413)   -32.5%
Total assets  $30,522    100.0%  $31,770    100.0%   (1,900)   -6.0%
                               
Capital Resources                              
Demand or current  $13,613    45.6%  $8,652    27.2%  $4,961    57.3%
Long term   13,506    44.2%   10,636    33.5%   2,870    27.0%
Total debt   27,619    90.8%   19,288    60.7%   7,831    40.6%
                               
Series A preferred   2,745    9.2%   2,745    8.6%       0.0%
Common   (9,024)   -30.2%   (194)   -0.6%   (8,830)   4551.4%
Accumulated other comprehensive income   444    1.5%   147    0.5%   297    202.0%
Non-controlling interest   523    1.8%       0.0%   523    na   
Total equity   (5,312)   -17.8%   2,698    8.5%   (8,010)   -296.9%
Total capitalization  $21,807    73.0%  $21,986    69.1%  $(365)   -1.7%

 

 

1 - The closest GAAP measure to "total liquid assets" is total current assets which were $18,983 as of September 30, 2015 and $26,619 as of December 31, 2014.

 

The table below summarizes our primary sources and uses of cash for the nine months ended September 30, 2015 and 2014 as derived from the statements of cash flows included in this Form 10-Q.

 

   For the Nine Months Ended September 30, 
Dollars in thousands          Increase (decrease) 
   2015   2014   Dollars   Percent 
Net cash provided by (used in):                    
Operating activities  $390   $733   $(343)   (46.8)%
Investing activities   (1,025)   (3,243)   2,218    (68.4)%
Financing activities   (76)   1,897    (1,973)   (104)%
Net cash flow   (711)   (613)   (98)   16.0%
                     
Effect of exchange rate changes on cash   660    360    300    83.3%
                     
Cash - unrestricted:                    
Beginning of period   2,397    3,190    (793)   -24.9%
End of period  $2,346   $2,938   $(519)   -20.1%

 

For the nine month period ended September 30, 2015, we generated $390,000 from operating activities. The largest source of cash from operations was a decrease in trading accounts and deposits of $7,159,000 due to the sale of TCP and exiting the FTR market while the largest use was a $3,634,000 decrease in accrued compensation. Accounts payable also increased by $1,244,000 mainly for the cost of retail electricity sold, which was directly related to the growth in the customer count during the period. Growth in accounts receivable also used $2,066,020 of cash.

 

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During the nine months ended September 31, 2015, we used $1,025,000 of cash for investing activities, primarily due to a net purchase of marketable securities of $256,000 and the increase of $481,000 towards development of real estate. For the same period, we used $76,000 of cash from financing activities. Our total debt net of repayments, increased by $6,368,000 and we paid of $6,144,000 in distributions. Of the total distributions amount, $412,000 was paid to the holder of our preferred units and $5,732,000 was paid to our common unit holders.

 

For the nine months ended September 30, 2014, we generated $733,000 from operating activities. The largest source of cash from operations was net income of $5,861,000 and the major use was an increase in cash in trading accounts of $9,085,000. During 2014, we used $3,243,000 of cash for investing activities, with the largest expenditures being for $999,000 to secure our position with the Canadian court in conjunction with the former employee litigation, the purchase of marketable securities of $914,000, our investment in Ultra Green’s convertible notes of $1,567,000, and the acquisition of DEG for $680,000. For the period, the Company generated net cash of $1,897,000 from financing activities, including a net increase in debt of $5,935,000 (to $16,348,000 at September 30, 2014 from $10,185,000 as of December 31, 2013), and payment of $4,039,000 in distributions. Of the total distribution amount, $412,000 was paid to the holder of our preferred units and $3,627,000 was paid to our common unit holders.

 

Financing

 

In February 2012, we executed a $25,000,000 Margin Line with ABN AMRO. The Margin Agreement provides CEF with an uncommitted $25,000,000 revolving line of credit for which it pays a commitment fee of $35,000 per month. Loans under the Margin Agreement are secured by all balances in CEF’s trading accounts with ABN AMRO, are payable on demand, and bear interest at an annual rate equal to 1.00% in excess of the Federal Funds Target Rate, or approximately 1.25%. Under the original Margin Agreement, the Company was also subject to certain reporting, affirmative, and negative covenants, including maintenance of minimum account net liquidating equity as defined of $3,000,000, a maximum loan ratio as defined of 12.5:1, and minimum consolidated tangible net worth of 4% of the amount of the Margin Line or $1,000,000. The Margin Agreement was amended on May 31, 2013 to reduce the uncommitted credit line to $15,000,000, the commitment fee to $25,000 per month, and the covenant with respect to net liquidating equity as defined to $1,500,000. There were no borrowings outstanding under the Margin Line as of September 30, 2015.

 

On May 10, 2012, our registration statement on Form S-1 relating to the offer and sale of our Renewable Unsecured Subordinated Notes (File No. 333-179460) was declared effective by the SEC, and the offering commenced on May 15, 2012. The registration statement on Form S-1 covers up to $50,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes. For the nine month periods ended September 30, 2015 and 2014, we incurred $1,666,000 and $992,000, respectively, of offering-related expenses, including marketing and printing expense, legal and accounting fees, filing fees, and trustee fees. These costs and expenses are expensed as incurred. From the effective date of May 10, 2012 through November 6, 2015, the termination date of the offering under the 2012 Form S-1, we sold a total of $29,109,000 in principal amount of Notes and repaid $5,524,000, for a net raise of $23,585,000.

 

On May 8, 2015, we filed a replacement registration statement on Form S-1 relating to the offer and sale of our Notes (File No. 333-203994). The 2015 Form S-1 covers up to $75,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes. The registration statement was declared effective by the SEC on November 13, 2015 and the offering recommenced on November 13, 2015.

 

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On May 12, 2014, the Company drew $700,000 under RBC Line. Advances under the RBC Line bear interest at a variable annual interest rate of 1 month LIBOR plus 2.25% set at the time of advance for a 30 day term, mature at various dates, and are collateralized by assets held in the Company’s marketable securities account. RBC is not obligated to make any extensions of credit to the Company and availability of funds may be increased or decreased by RBC in its sole and absolute discretion. Prepayment of any outstanding principal under the RBC Line may subject the Company to LIBOR break funding costs. There were no borrowings outstanding under the RBC Line as of September 30, 2015

 

On June 16, 2014, the Company purchased a single family home in Garrison, Minnesota for use as a corporate retreat for a purchase price of $285,000, paid with $57,000 of cash and the proceeds of a $228,000 note advanced by Security State Bank and secured by a first mortgage. The loan is payable in 239 equal installments of $1,482 due on the 16th of each month beginning on July 16, 2014 and one irregular installment of $1,482 due on June 16, 2034 (the “maturity date”). The note bears interest at an annual rate equal to the prime rate as published from time to time by The Wall Street Journal plus 0.75%, subject to a floor of 4.75%. Whenever increases occur in the interest rate, Security State Bank, at its option and with notice to the Company, may: (a) increase the Company’s payments to insure the loan will be paid off by the maturity date; (b) increase the Company’s payments to cover accruing interest; (c) increase the number of the Company’s payments; or (d) continue the payments at the same amount and increase the Company’s final payment. The loan may be prepaid in whole or in part at any time without penalty.

 

On October 14, 2014, REH, TSE, and TSEE entered into a Credit Agreement with the Toronto, Ontario branch of Maple Bank GmbH, expiring October 31, 2016. The Maple Agreement provides the Company’s retail energy services businesses with a revolving line of credit of up to $5,000,000 in committed amount secured by a first position security interest in all of the assets of REH and its subsidiaries, a pledge of the equity of such businesses by the Company, and certain validity and financial guarantees. Availability of loans is keyed to advance rates against eligible receivables as defined. Any loans outstanding bear interest at an annual rate equal to 3 month LIBOR, subject to a floor of 0.50%, plus a margin of 6.00%. In addition, the Company is obligated to pay an annual fee of 1.00% of the committed amount on a monthly basis and a monthly non-use fee of 1.00% of the difference between the committed amount and the average daily principal balance of any outstanding loans. The Company is also subject to certain customary reporting, affirmative, and negative covenants. On August 4, 2015, the Maple Revolver was amended to increase the committed amount to $7,500,000. As of September 30, 2015, there was $2,663,000 outstanding under the Maple Revolver.

 

Citizens Independent Bank

 

On July 24, 2014, Noble, entered into a line of credit agreement with Citizens Independent Bank, expiring August 1, 2015. The agreement provides Noble with a line of credit of up to $500,000 in committed amount secured by property and assets as the lender may require and guarantees. Availability of loans is keyed to advance rates against certain eligible receivables as defined. Any loans outstanding bear interest at 1% above the base rate established by the bank. Noble is also subject to certain reporting, affirmative, negative covenants, and must pay down the line to $250,000 for a thirty consecutive day period. As of September 30, 2015, there was $245,700 outstanding under the agreement and were in negotiations with the lender on the terms of the line.

 

US Bank Cash Flow Manager

 

On October 21, 2013, Noble, entered into a line of credit agreement with US Bank Cash Flow Manager, with all advances maturing on February 19, 2020. The agreement provides Noble with a line of credit of up to $250,000 in committed amount secured by personal guarantees of the owners of Noble. Any loans outstanding bear interest at an annual rate equal to prime plus 4.5%. As of September 30, 2015, there was $67,178 outstanding under the agreement.

 

Ford Credit

 

On June 13, 2014, Noble entered into a loan agreement with Ford Credit for the purchase of a vehicle. The note calls for sixty monthly payments of $664.43, bears interest at 6.7%, and is secured by the vehicle. As of September 30, 2015, the balance remaining on the note was $26,357.

 

Ally Financial

 

On December 26, 2012, Noble entered in a loan agreement Ally Financial for the purchase of a vehicle. The note calls for seventy two monthly payments of $587.65, bears interest at 4.9%, and is secured by the vehicle. As of September 30, 2015, the balance remaining on the note was $22,100.

 

On November 21, 2014, American Land and Cyclone entered into four construction loan agreements, each for a committed amount of $205,000 or $820,000 in total. Each commitment is secured by a mortgage on a lot (numbers 1, 2, 3, and 4) in Block 1 of Fox Meadows 3rd Addition and is also personally guaranteed by Mr. Krieger. Fox Meadows is a townhouse development located in Lakeville, Minnesota in which Cyclone owns 35 attached residential building sites. Proceeds of the Construction Loans will be used to construct the first four spec/model homes on Cyclone’s Fox Meadows property. Draws on the Fox Meadows Construction Loans bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10th, the notes mature on November 21, 2015, and will renew for an additional three months if not paid by then. The loans may be prepaid in whole or in part at any time without penalty.

 

On February 24, 2015, American Land and Cyclone entered into a construction loan agreement for a committed amount of $485,000 secured by a mortgage on Lot 2, Block 1, Territory 1st Addition, also referred to as “21580 Bitterbush Pass”. The loan is personally guaranteed by Mr. Krieger and proceeds will be used to construct a home on the property. Draws bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10th and the note matures on November 24, 2015. The loan may be prepaid in whole or in part at any time without penalty.

 

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As of September 30, 2015, there was $1,075,000 outstanding under the American Land Construction Loans and the Company was in compliance with all terms and conditions of the agreements.

 

On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon, a related party, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a $120,000 note secured by a mortgage on the property and owed to Lakeview Bank (the “Lakeview Bank Mortgage”). The Lakeview Bank Mortgage bears interest at the highest prime rate reported as such from time to time by The Wall Street Journal. Interest only is payable monthly on the 25th, the note matures on April 30, 2016. The loan may be prepaid in whole or in part at any time without penalty. As of September 30, 2015, there was $120,000 outstanding under the Lakeview Bank Mortgage.

 

Effective June 28, 2013, pursuant to a Membership Unit Purchase Agreement, Mr. Krieger purchased 100% of the outstanding issue or 496 redeemable preferred units from Mr. John O. Hanson. Concurrently with the purchase, Mr. Krieger and the Company exchanged the redeemable preferred units for an identical number of new Series A Preferred Units (the “Series A Preferred”) and the redeemable preferred units were cancelled. The Series A Preferred is not redeemable, callable, or convertible, is non-voting with respect to elections to the Company’s Board of Governors, is senior to the Company’s common equity units with respect to rights in liquidation, and is entitled to distributions out of legally available funds in the amount of $92.25 per unit per month.

 

Non-GAAP Financial Measures

 

The Company’s communications may include certain non-GAAP financial measures. A “non-GAAP financial measure” is defined as a numerical measure of a company's financial performance, financial position, or cash flows that excludes, or includes, amounts that are included in, or excluded from, the most directly comparable measure calculated and presented in accordance with GAAP in the company's financial statements.

 

Non-GAAP financial measures utilized by the Company “total liquid assets.” The most comparable GAAP measure is total current assets. The Company’s management believes that this non-GAAP financial measure provides useful information to investors and enables investors and analysts to more accurately compare the Company's ongoing financial performance over the periods presented.

 

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Critical Accounting Policies and Estimates

 

Principles of Consolidation and Variable Interest Entities

 

The Company evaluates the need to consolidate affiliates based on standards set forth in the FASB’s ASC 810 Consolidation and follows ASC 810-10-15 guidance with respect to accounting for variable interest entities (“VIEs”).

 

In determining whether or not we are required to consolidate the accounts of an entity, management considers factors such as our ownership interest, our authority to make decisions, the contractual and substantive participating rights of equity holders, and whether or not the entity is a VIE in which we have a controlling financial interest.

 

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties or whose equity investors lack any of the characteristics of a controlling financial interest. A variable interest is an investment or other interest that will absorb portions of a VIE’s expected losses or receive portions of the entity’s expected residual returns. Variable interests are contractual, ownership, or other pecuniary interests that change with changes in the fair value of the entity’s net assets. A party is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides the party with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of the power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances.

 

Business Combinations, Acquisitions, and Non-Controlling Interests

 

The Company accounts for business combinations in accordance with ASC 805, Business Combinations (“ASC 805”), which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquisition at fair value at the transaction date. The excess of the cost of the acquisition over the interest in the fair value of the identifiable net assets acquired is recorded as goodwill. Transaction costs are expensed as incurred.

 

Acquisitions are recorded based upon preliminary allocations of the purchase price to management’s assessment of the fair values of tangible and intangible assets acquired and any liabilities assumed. The allocation process involves a considerable amount of subjective judgment, and preliminary estimates of fair value are subject to adjustment as additional information is obtained and finalized, up to one year after the date of acquisition. Estimates are based on assumptions the Company believes to be reasonable, however, actual results may differ from these estimates.

 

Ownership interests in an operating entity are represented by the number of units owned and income is allocated to owners based on the ratio of their holdings to the total units outstanding during the period. Capital contributions, distributions, syndication costs, and profits and losses are allocated to non-controlling interests in accordance with the entity’s governance documents.

 

Revenue Recognition and Commodity Derivative Instruments

 

Revenues in our wholesale trading business are derived from trading financial, physical, and derivative energy contracts while those for our retail segment result from electricity sales to end-use consumers. In our trading activities, contracts with the exchanges on which we trade permit net settlement, including the right to offset cash collateral in the settlement process. Accordingly, we net cash collateral against the derivative position in the accompanying consolidated balance sheets. All realized and unrealized gains and losses on derivative instruments are recorded in revenues. Revenue from the retail sale of electricity, including estimates of unbilled revenues for power consumed by customers but not yet billed under the cycle billing method, is recorded in the period in which customers consume the commodity, net of any applicable sales tax.

 

Hedge Accounting

 

In our retail business, we are exposed to volatility in the cost of energy acquired for sale to customers, and as a result, in October 2012, we began using derivatives to hedge or reduce this variability, since changes in the price of certain derivatives are expected to be highly effective at offsetting changes in this cost.

 

For a cash flow hedge, the effective portion of any change in the hedging instrument’s fair value is recorded as other comprehensive income until the change in value of the hedged item is recognized in earnings. To qualify for hedge accounting, the hedge relationships must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis.

 

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Fair Value Measurements

 

FASB’s Fair Value Measurement Topic establishes a hierarchy of inputs with respect to determining the fair value of assets and liabilities for financial reporting purposes. The three types of inputs are “Level 1” (quoted prices in active markets for identical assets or liabilities), “Level 2” (inputs other than quoted prices that are observable either directly or indirectly for the asset or liability), and “Level 3” (unobservable inputs for which little or no market data exists). Financial instruments that are not traded in publicly quoted markets or that are acquired based on prices and terms determined by direct negotiation with the issuer are classified as Level 3 and carried at book value, which management believes approximates fair value, until circumstances otherwise dictate.

 

With respect to Level 3 inputs in particular, significant increases or decreases in specific inputs in isolation could result in higher or lower fair value measurements and the methods and calculations used by the Company to estimate fair values may not be indicative of net realizable value or reflective of future fair values. Furthermore, the use of different methodologies or assumptions to determine fair values could result in different fair value measurements and such variations could be material. In addition to management’s assessments, from time to time, the Company may engage third parties such as appraisers, brokers, or investment bankers to assist management in its valuation and classification of financial instruments.

 

Real Estate Development

 

Revenues from real estate developments, if any, are recognized at the time of sale closing if all significant conditions are satisfied, including adequate down payment, reasonable assurance of collectability of any notes received, and completion of other contract requirements. Recognition of all or part of the revenue is deferred if any significant conditions are not satisfied. Costs that relate directly to development projects are capitalized and allocated using the specific identification method. Land acquisition, improvements, and holding costs, including real estate taxes and interest are capitalized while a development is in progress. Interest expense, if any, is capitalized based on specific identification of notes payable issued to finance specific assets under development. Once development on a project has been completed and sales have begun, remaining inventory is recorded at the lower of cost or market. Development costs are charged to cost of sales when the related revenue is recognized or when a development is abandoned.

 

Profits Interest Payments

 

One of our current second-tier subsidiaries (CEF) has Class B members as did SUM. Under the terms of such subsidiary’s member control agreement, Class B members have no voting rights, are not required to contribute capital, and have no rights to distributions following termination of employment, but are entitled to a defined share of profits while employed. Since Class B members have no corporate governance rights or risk of capital loss (or gain), they do not own non-controlling equity interests and profits interest payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the balance sheet.

 

For the three and nine month periods ended September 30, 2015 and 2014, we recorded $66,000, $143,000, $2,339,000, and $5,567,000, respectively, in compensation and benefits, representing the allocation of profits to Class B members. The amount of accrued profits interests included in accrued compensation at September 30, 2015 and 2014 was $255,000 and $150,000, respectively.

 

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Item 3 - Quantitative and Qualitative Disclosures about Market Risk

 

We are exposed to market risk in our normal business activities. Market risk is the potential loss that may result from changes associated with an existing or forecasted financial or commodity transaction. The types of market risk we are exposed to are commodity price, interest rate, liquidity, credit, and currency exchange. In order to manage these risks, we may use various fixed price forward purchase and sales contracts, futures and option contracts, and swaps and options traded in the over-the-counter financial markets.

 

Commodity Price Risk

 

Commodity price risks result from exposure to volatility or changes in spot and forward prices and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits.

 

We manage the commodity price risk associated with our retail load serving obligations by entering into various contracts to hedge variability in future cash flows due to forecasted sales and purchases of electricity. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges as well as in over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.

 

In our wholesale trading businesses, we measure the risk of our portfolio using several analytical methods, including position limits, stop loss, stress testing, and VaR. Our daily long term VaR model is based upon log-normal returns calculated from the last 30 business days of prices at the 95% confidence level (1.645 standard deviations) with a one day liquidity assumption. Our short term VaR model measures the risk of virtual and up-to-congestion transactions and is based upon 4 years of seasonal prices at the 95% confidence level with a one day liquidity assumption. VaR is calculated daily, using positions and prices updated to the close of business on the previous day. The price history used is ideally that of the instrument held; however, in those cases where such prices are unavailable, benchmarking is used. Our VaR calculations always use the market value of the position, not its cost. In the case of a position which is likely to take more than a day to close out, VaR is multiplied by the square root of the average days to liquidate, assuming a stressed market.

 

The VaR model we apply to FTRs (“illiquid VaR”) is based upon 5 years of seasonal prices at the 95% confidence level but with no liquidity assumption, that is, we assume we will be unable to exit the position prior to its maturity due to a lack of trading activity. As a result of this liquidity assumption, the VaR of our FTRs may not be added to that of our other positions. As of September 30, 2015 and 2014, the longest tenor of our FTR positions was zero and 8 months, respectively.

 

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The following table summarizes our liquid VaR as of and for the nine months ended September 30, 2015 and 2014:

 

   At/for nine months ended
September 30,
   Increase (decrease) 
  2015   2014   Units   Percent 
Liquid VaR                
As of period end  $380,518   $437,895   $(57,377)   -13.1%
For the period:                    
Minimum  $309,855   $38,174   $271,681    711.7%
Average   749,318    693,581    55,737    8.0%
Maximum   1,781,771    3,343,448    (1,561,677)   -46.7%
                     
VaR, pct of cash in trading accounts                    
As of period end   4.27%   2.65%   1.61%   60.8%
For the period:                    
Minimum (1)   2.06%   0.28%   1.78%   629.9%
Average (1)   4.99%   5.14%   -0.15%   -2.8%
Maximum (1)   11.87%   24.77%   -12.90%   -52.1%

 

 

1 - Dollar VaR divided by the average balance of cash in trading accounts for the period.

 

Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market derivative instruments assets and liabilities could differ from the calculated VaR, and such changes could have a material impact on our financial results.

 

The value of the derivative financial instruments we hold for trading purposes and as cash flow hedges is significantly influenced by forward commodity prices. Periodic changes in forward prices could cause significant changes in the marked-to-market (“MTM”) valuation of these contracts. For example, assuming that all other variables remain constant:

 

   Average percentage change in
mark-to-market valuation
   Dollar change in
mark-to-market valuation
 
Percentage change in forward price from September 30, 2015   Derivatives held for trading   Economic hedges   Cash flow hedges   Derivatives held for trading   Economic hedges   Cash flow hedges 
 10%   286.4%   54.5%   17.3%   31,121    27,570    2,429 
 5%   143.2%   27.3%   8.6%   15,561    13,785    1,214 
 1%   28.6%   5.5%   1.7%   3,112    2,757    243 
 -1%   -28.6%   -5.5%   -1.7%   (3,112)   (2,757)   (243)
 -5%   -143.2%   -27.3%   -8.6%   (15,561)   (13,785)   (1,214)
 -10%   -286.4%   -54.5%   -17.3%   (31,121)   (27,570)   (2,429)

 

Interest Rate Risk

 

As of September 30, 2015, we had $4,439,000 of variable rate debt outstanding and at December 31, 2014, we had $1,635,000 of such debt outstanding. The interest rates charged on such are based in part on changes in certain market indices plus a credit margin, but are subject to “floors”, which may have the effect of converting variable rates to fixed rates and such was the case at September 30, 2015 and December 31, 2014. Consequently, at either date, we had no variable rate debt, although in the future we may be exposed to fluctuations in interest rates. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars, and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument.

 

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Liquidity Risk

 

Liquidity risk arises from our general funding needs and the management of our assets and liabilities. We are exposed to additional collateral posting or margin requirements with market operators if price volatility or levels increase. Based on a sensitivity analysis for positions under marginable contracts, a 20% change in electricity prices would cause an increase in margin collateral posted of approximately $122,000 as of September 30, 2015. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2015.

 

Wholesale Counterparty Credit Risk

 

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. We monitor and manage credit risk through the credit policies described in “Item 1 - Business – Wholesale Trading – Credit Risk Management” of our 2014 Form 10-K. Given the credit quality, diversification, and term of the exposure in the portfolio, we do not anticipate a material impact on financial position or results of operations from nonperformance by any counterparty.

 

Retail Customer Credit Risk

 

In our retail business, we may be exposed to certain customer credit risks. Although we are currently not exposed to retail customer credit risk to a large degree due to our participation in POR programs, we expect that this situation will change as we grow our retail business and expand into non-POR areas. Furthermore, economic and market conditions may affect our customers' willingness and ability to pay their bills in a timely manner, which could lead to an increase in bad debt expense above and beyond the allowance for uncollectible accounts charged to us by utilities. In general, we intend to manage retail credit risk as described in “Item 1 - Business – Retail Energy Services – Credit Risk Management” of our 2014 Form 10-K.

 

Foreign Exchange Risk

 

A portion of our assets and liabilities are denominated in Canadian dollars and are therefore subject to fluctuations in exchange rates, however, we do not have any exposure to any highly inflationary foreign currencies. We believe our foreign currency exposure is limited.

 

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Item 4 - Controls and Procedures

 

The Company maintains a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

 

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of our disclosure controls and procedures as defined in Exchange Act Rules 13a-15(e) and 15d-15(e). Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2015, the Company’s disclosure controls and procedures were effective.

 

Changes in Internal Control over Financial Reporting

 

There was no change in the Company’s internal control over financial reporting that occurred during the three months ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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Part II – Other Information

 

Item 1 - Legal Proceedings

 

See “Note 19 - Commitments and Contingencies” on page 41 of this Form 10-Q for a discussion of certain legal proceedings.

 

Item 1A - Risk Factors

 

No material changes from prior disclosure.

 

Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds

 

None

 

Item 3 - Defaults Upon Senior Securities

 

None

 

Item 4 - Mine Safety Disclosures

 

None

 

Item 5 - Other Information

 

None

 

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Item 6 - Exhibits

 

Exhibit Number   Description
3.1   Amended and Restated Articles of Organization of Aspirity Holdings LLC (formerly known as Twin Cities Power Holdings, LLC), effective July 14, 2015 (incorporated by reference to Exhibit 3.1 to the Registrant's Form 8-K filed July 15, 2015).
3.2   Amended and Restated Bylaws of Aspirity Holdings LLC (formerly known as Twin Cities Power Holdings, LLC), effective July 14, 2015 (incorporated by reference to Exhibit 3.1 to the Registrant's Form 8-K filed July 15, 2015).
4.4   Aspirity Holdings LLC (formerly known as Twin Cities Power Holdings, LLC) Renewable Unsecured Subordinated Notes Subscription Agreement (incorporated by reference to Exhibit 4.4 to the Registrant's Form 8-K filed July 20, 2015).
10.1   Equity Interest Purchase Agreement, dated June 1, 2015, by and between Angell Energy, LLC and Twin Cities Power Holdings, LLC (incorporated by reference to Exhibit 10.1 to the Registrant's Form 10-Q/A filed August 17, 2015).
10.2   Secured Promissory Note, dated June 1, 2015, between Angell Energy, LLC and Twin Cities Power Holdings, LLC (incorporated by reference to Exhibit 10.2 to the Registrant's Form 10-Q/A filed August 17, 2015).
10.3   Security and Guarantee Agreement, dated June 1, 2015, by and among Angell Energy, LLC, Michael Angell, Twin Cities Power, LLC, Summit Energy, LLC, and Twin Cities Power Holdings, LLC (incorporated by reference to Exhibit 10.3 to the Registrant's Form 10-Q/A filed August 17, 2015).
10.4   Administrative Services Agreement, dated June 1, 2015, by and between Angell Energy, LLC and Apollo Energy Services, LLC (incorporated by reference to Exhibit 10.4 to the Registrant's Form 10-Q/A filed August 17, 2015).
10.5   DataLive Software License, dated June 1, 2015, by and between Apollo Energy Services, LLC and Angell Energy, LLC (incorporated by reference to Exhibit 10.5 to the Registrant's Form 10-Q/A filed August 17, 2015).
10.6   Office Sublease Agreement, dated June 4, 2015, by and between Bell State Bank & Trust and Aspirity Holdings LLC (formerly known as Twin Cities Power Holdings, LLC) (incorporated by reference to Exhibit 10.2 to the Registrant's Form 8-K filed July 20, 2015).
22.1   Form of Noteholder Solicitation Cover Letter, dated June 2, 2015 (incorporated by reference to Exhibit 22.1 to the Registrant's Form 8-K filed June 2, 2015).
22.2   Frequently Asked Questions, dated June 2, 2015 (incorporated by reference to Exhibit 22.2 to the Registrant's Form 8-K filed June 2, 2015).
22.3   Solicitation of Votes from Holders of the Renewable Unsecured Subordinated Notes of Twin Cities Power Holdings, LLC, dated June 2, 2015 (incorporated by reference to Exhibit 22.3 to the Registrant's Form 8-K filed June 2, 2015).
22.4   Form of Ballot, dated June 2, 2015 (incorporated by reference to Exhibit 22.4 to the Registrant's Form 8-K filed June 2, 2015).

 

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Exhibit Number   Description
31.1   Certification of Chief Executive Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2   Certification of Chief Financial Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
32.1   Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS   XBRL Instance Document
101.SCH   XBRL Schema Document
101.CAL   XBRL Calculation Linkbase Document
101.DEF   XBRL Definition Linkbase Document
101.LAB   XBRL Labels Linkbase Document
101.PRE   XBRL Presentation Linkbase Document

 

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Signatures

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

 

        ASPIRITY HOLDINGS LLC
         
         
         
Dated: November 16, 2015   By:  

/s/ Timothy S. Krieger

    Timothy S. Krieger
        Chief Executive Officer, President and Chairman of the Board (principal executive officer)
         
         
         
         
Dated: November 16, 2015   By:   /s/ Wiley H. Sharp III
        Wiley H. Sharp III
        Vice President – Finance and Chief Financial Officer (principal accounting and financial officer)

 

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