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EXCEL - IDEA: XBRL DOCUMENT - ASPIRITY HOLDINGS LLCFinancial_Report.xls
EX-10.1 - GUARANTY - ASPIRITY HOLDINGS LLCtwincities_10q-ex1001.htm
EX-10.3 - GUARANTY - ASPIRITY HOLDINGS LLCtwincities_10q-ex1003.htm
EX-32.1 - CERTIFICATION - ASPIRITY HOLDINGS LLCtwincities_10q-ex3201.htm
EX-10.2 - GUARANTY - ASPIRITY HOLDINGS LLCtwincities_10q-ex1002.htm
EX-31.1 - CHIEF EXECUTIVE OFFICER CERTIFICATION - ASPIRITY HOLDINGS LLCtwincities_10q-ex3101.htm
EX-31.2 - CHIEF FINANCIAL OFFICER CERTIFICATION - ASPIRITY HOLDINGS LLCtwincities_10q-ex3102.htm

UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-Q

 

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

 

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013

 

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: 333-179460

 

Twin Cities Power Holdings, LLC

(Exact name of registrant as specified in its charter)

 

Minnesota   27-1658449
(State of organization)   (IRS Employer Identification Number)
 
 

16233 Kenyon Avenue, Suite 210

Lakeville, Minnesota 55044

 
  (Address of principal executive offices, zip code)  
     
  (952) 241-3103  
  (Registrant’s telephone number, including area code)  
     
  not applicable  
  (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 S     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 S      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 S

 

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

 

 

 

TABLE OF CONTENTS

 

Definitions   3 
Forward Looking Statements   6 
Non-GAAP Financial Measures   7 
Part I – Financial Information   8 
Item 1 - Financial Statements (Unaudited)   8 
Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012   8 
Consolidated Statements of Comprehensive Income Three Months ended March 31, 2013 and 2012   9 
Consolidated Statements of Cash Flows Three Months Ended March 31, 2013 and 2012   10 
Notes to Consolidated Financial Statements   12 
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations   29 
Industry Background   29 
Company Overview   33 
Liquidity, Capital Resources, and Cash Flow   42 
Financing   44 
Non-GAAP Financial Measures   45 
Critical Accounting Policies and Estimates   45 
Item 3 - Quantitative and Qualitative Disclosures about Market Risk   46 
Item 4 - Controls and Procedures   46 
Part II – Other Information   47 
Item 1 - Legal Proceedings   47 
Item 1A - Risk Factors   47 
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds   47 
Item 3 - Defaults Upon Senior Securities   47 
Item 4 - Mine Safety Disclosures   47 
Item 5 - Other Information   47 
Item 6 - Exhibits   48 
Signatures   49 

 

2
 

 

Definitions

 

Abbreviation or acronym   Definition
ABN AMRO   ABN AMRO Clearing Chicago, LLC and ABN AMRO Clearing Bank, N.V.
ASC   Accounting Standards Codification
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 one hundred thousand Btu. A “MMBtu” is one million Btu.
C$   Canadian dollars
CAN   Twin Cities Power – Canada, Ltd., a wholly-owned subsidiary of TCE and a second-tier subsidiary of the Company, which has ceased operations
CCL   Clearwaters Capital, LLC, an affiliate of Schachter
CEF   Cygnus Energy Futures, LLC, a wholly-owned subsidiary of CP and a second-tier subsidiary of the Company
CFTC   Commodity Futures Trading Commission
CLP   Connecticut Light & Power Company, an EDC in Connecticut
CME   CME Group
Company   TCPH and its subsidiaries
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 first-tier subsidiary of the Company
CP&U   Community Power & Utility, LLC
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 TCP 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

 

3
 

 

 

Abbreviation or acronym   Definition
EDC   Electric distribution company
EIA   Energy Information Administration, an independent agency within DOE
ERCOT   Electric Reliability Council of Texas
FASB   Financial Accounting Standards Board
FERC   Federal Energy Regulatory Commission, an independent regulatory agency within DOE
Form S-1   The Company’s Registration Statement on Form S-1, declared effective by the Securities and Exchange Commission on May 10, 2012, with respect to the Company’s Notes Offering
GAAP   Generally accepted accounting principles in the United States
HTS   HTS Capital, LLC, an affiliate of Schachter
HTS Parties   Schachter, HTS, and CCL collectively
ICE   Intercontinental Exchange®
ISO   Independent System Operator
ISO-NE   ISO New England
kW; kWh   Kilowatt or kilowatt-hour; 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.
MISO   Midwest Independent System Operator
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.
MW; MWh   Megawatt or megawatt-hour; 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.
NGX   Natural Gas Exchange Inc.
NOAA   National Oceanic and Atmospheric Administration, an agency of the U.S. Department of Commerce
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 pursuant to a registration statement on Form S-1 declared effective by the SEC on May 10, 2012
NYISO   New York Independent System Operator
OTC   Over-the-counter
PJM   PJM Interconnection
POR and 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.

 

4
 

 

Abbreviation or acronym   Definition
PURPA   Public Utilities Regulatory Policy Act of 1978
RTO   Regional Transmission Organization
Schachter   Robert O. Schachter, an individual
SEC   U.S. Securities and Exchange Commission
SUM   Summit Energy, LLC, a wholly-owned subsidiary of TCP and a second-tier subsidiary of the Company
TCE   Twin Cities Energy, LLC, a first-tier subsidiary of the Company
TCP   Twin Cities Power, LLC, a first-tier subsidiary of the Company
TCPH   Twin Cities Power Holdings, LLC, the Company
TSE   Town Square Energy, a division of TCP resulting from the acquisition of the business and assets of CP&U. In March 2013, TCP began the process of reorganizing TSE as a wholly-owned, first-tier subsidiary of the Company
UI   The United Illuminating Company, an EDC in Connecticut
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. Energy is measured in joules and power is measured in watts. A watt is equal to one joule per second.   In the case of electricity, power is also 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.   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 25 hours or a 50-watt bulb for 20 hours.   Multiples and sub-multiples of watts and watt-hours are measured using International Systems of Units (“SI”) conventions as follows:

     
    Common Multiples for Watts and Watt-hours
    Multiple Symbols Names
    one thousand (1,000) kW or kWh kilowatt or kilowatt-hour
    one million (1,000,000) MW or MWh megawatt or megawatt-hour
    one billion (1,000,000,000) GW or GWh gigawatt or gigawatt-hour
    one trillion (1,000,000,000,000) TW or TWh terawatt or terawatt-hour

 

 

5
 

 

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 are 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; and
·Our strategies for risk management.
·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 2012 (the “2012 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.

 

6
 

 

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 presentations of liquidity measures and debt-to-equity ratios. 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.

 

7
 

 

Part I – Financial Information

 

Item 1 - Financial Statements (Unaudited)

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Balance Sheets

As of March 31, 2013 and December 31, 2012

 

   March 31,  December 31,
   2013  2012
   Unaudited   
Assets          
           
Current assets          
Cash  $1,010,418   $771,852 
Trading accounts and deposits   13,439,937    12,025,023 
Accounts receivable - trade   1,112,841    2,191,267 
Prepaid expenses and other assets   339,190    189,808 
Total current assets   15,902,386    15,177,950 
           
Equipment and furniture, net   550,406    571,232 
           
Other assets          
Intangible assets, net   545,489    125,326 
Deferred financing costs, net   383,323    388,979 
Total assets  $17,381,604   $16,263,487 
           
Liabilities and Members' Equity          
           
Current liabilities          
Accounts payable - trade  $1,433,748   $1,469,301 
Accrued expenses   174,136    70,378 
Accrued compensation   2,380,154    1,984,388 
Accrued interest   235,479    44,472 
Accrued distributions   16,899    15,867 
Notes payable, related parties   366,667    866,665 
Notes payable   3,400,257    3,400,262 
Renewable unsecured subordinated notes   1,182,000    738,693 
Obligations under non-competition agreement   250,000     
Total current liabilities   9,439,340    8,590,026 
           
Long-term debt & other liabilities          
Renewable unsecured subordinated notes   1,855,689    1,274,445 
Obligations under non-competition agreement   187,500     
Total liabilities   11,482,529    9,864,471 
           
Commitments and contingencies          
           
Redeemable preferred units   2,745,000    2,745,000 
           
Members' equity          
Common equity   2,602,777    3,196,737 
Accumulated other comprehensive income   551,298    457,279 
Total members' equity   3,154,075    3,654,016 
Total liabilities and members' equity  $17,381,604   $16,263,487 

 

See notes to consolidated financial statements.

8
 

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Comprehensive Income

Three Months ended March 31, 2013 and 2012

 

   Three Months
   Ended March 31,
   2013  2012
   Unaudited  Unaudited
Revenue          
Wholesale trading revenue, net  $6,797,068   $3,812,637 
Retail electricity revenue   1,437,329     
    8,234,397    3,812,637 
           
Costs and expenses          
Cost of retail electricity sold   1,684,382     
Retail sales and marketing   388     
Compensation and benefits   3,600,612    2,100,761 
Professional fees   927,188    625,049 
Other general and administrative   632,052    343,511 
Trading tools and subscriptions   222,620    202,178 
    7,067,242    3,271,499 
           
Operating income   1,167,155    541,138 
           
Other income (expense)          
Interest expense   (348,821)   (365,410)
Interest income   7,533    9,914 
Gain (loss) on foreign currency exchange   246    (8,639)
    (341,042)   (364,135)
           
Income before income taxes   826,113    177,003 
Income tax provision       37,282 
           
Net income   826,113    139,721 
Preferred distributions   (137,250)   (91,500)
Net income attributable to common   688,863    48,221 
           
Other comprehensive income (loss)          
Foreign currency translation adjustment   (37,074)   19,012 
Change in fair value of cash flow hedges   131,093     
Comprehensive income  $782,882   $67,233 

 

See notes to consolidated financial statements.

 

9
 

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Cash Flows

Three Months Ended March 31, 2013 and 2012

 

   Three Months
   Ended March 31,
   2013  2012
   Unaudited  Unaudited
Cash flows from operating activities          
Net income  $826,113   $139,721 
Adjustments to reconcile net income to net cash provided by operating activities:          
Depreciation and amortization   134,193    51,600 
(Increase) decrease in:          
Trading accounts and deposits   (1,283,821)   1,582,767 
Accounts receivable - trade   1,078,427    167,734 
Prepaid expenses and other assets   (149,382)   (60,463)
Increase (decrease) in:          
Accounts payable - trade   (35,555)   505,214 
Accrued expenses   103,758    (5,968)
Accrued compensation   395,766    (1,002,427)
Accrued interest   191,007    (145,169)
Net cash provided by operating activities   1,260,506    1,233,009 
           
Cash flows from investing activities          
Purchase of equipment and furniture   (27,874)   (56,100)
Payments on obligations under non-competition agreement   (62,500)    
Net cash used in investing activities   (90,374)   (56,100)
           
Cash flows from financing activities          
Deferred financing costs       (295,133)
Payments on notes payable   (500,000)   (485,751)
Issuance of renewable unsecured subordinated notes   1,106,548     
Redemption of renewable unsecured subordinated notes   (82,000)    
Preferred distributions   (136,218)   (58,386)
Common distributions   (1,282,823)   (110,000)
Redemption of common units       (100,000)
Net cash used in financing activities   (894,493)   (1,049,270)
           
Net increase in cash   275,639    127,639 
Effect of exchange rate changes on cash   (37,073)   (10,673)
           
Cash:          
Beginning of period   771,852    971,081 
End of period  $1,010,418   $1,088,047 

 

See notes to consolidated financial statements.

 

10
 

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Cash Flows (Continued)

Three Months Ended March 31, 2013 and 2012

 

   Three Months
   Ended March 31,
   2013  2012
   Unaudited  Unaudited
Non-cash investing and financing activities:          
           
Effective portion of cash flow hedge  $49,061   $ 
Obligations under non-competition agreement  $500,000   $ 
Redeemable preferred units issued in exchange for certain notes payable  $   $2,745,000 
Accrued distributions - preferred  $1,032   $33,114 
Accrued distributions - common  $15,867   $ 
           
Supplemental disclosures of cash flow information:          
Cash payments for interest  $157,814   $475,892 

 

See notes to consolidated financial statements.

 

11
 

 

Twin Cities Power Holdings, LLC and Subsidiaries

Notes to Consolidated Financial Statements

 

1.Basis of Presentation and Description of Business

 

Basis of Presentation

 

Twin Cities Power Holdings, LLC (“TCPH” or the “Company”) 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 TCPH 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, 2012 and 2011 included in our 2012 Form 10-K.

 

Businesses

 

Twin Cities Power Holdings, LLC (“TCPH” or the “Company”) is a Minnesota Limited Liability Company formed on December 30, 2009, but had no assets or operations prior to December 31, 2011. The Company, through its subsidiaries, has market-based rate authority granted by the Federal Energy Regulatory Commission, an independent regulatory agency within the U.S. Department of Energy (“FERC” and “DOE”, respectively), is authorized by DOE to export electricity to Canada, is licensed by the states of Connecticut, Massachusetts, and Rhode Island as an electric supplier to retail customers (operations have yet to begin in Massachusetts and Rhode Island), and has a retail electric supplier license application pending in New Hampshire. Consequently, the Company has two business segments used to measure its activity – wholesale trading and retail energy services.

 

Wholesale Energy Trading

 

The Company trades financial and physical contracts in wholesale electricity markets managed by Independent System Operators or Regional Transmission Organizations (collectively, the “ISOs”) including those managed by the Midwest Independent System Operator (“MISO”), the Electric Reliability Council of Texas (“ERCOT”), the PJM Interconnection (“PJM”), ISO New England (“ISO-NE”), and the New York Independent System Operator (“NYISO”). 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”). U.S. ISOs are regulated by FERC. The Commodity Futures Trading Commission (“CFTC”) regulates ICE, NGX, and CME.

 

In general, the Company’s trading activities are characterized by the acquisition of electricity or other energy-related commodities at a given location 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. ISO-traded financial contracts are also known as virtual trades, are outstanding overnight, and settle the next day. The Company also trades physical electricity between certain markets, buying in one market and selling in another. On ICE, NGX, and CME, from time to time, the Company may trade electricity, natural gas, and oil derivatives and hold an open interest in these contracts overnight or longer.

 

12
 

 

Regardless of the market or contract type, non-rated participants such as the Company are typically required to place cash collateral with market operators in order to trade, with the specific amounts of such depending upon the rules and requirements of the particular market.

 

Retail Energy Services

 

On June 29, 2012, a subsidiary of the Company, Twin Cities Power, LLC, (“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. The business was re-named Town Square Energy (“TSE”), and beginning on July 1, 2012, the Company began selling electricity to retail accounts. Initially, TSE was run as a division of TCP. In March 2013, the Company began the process of reorganizing TSE as a wholly-owned subsidiary of TCPH.

 

2.Summary of Significant Accounting Policies

 

A description of our significant accounting policies is included in the 2012 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 month period ended March 31, 2013 are not necessarily indicative of the results expected for the year ending December 31, 2013.

 

Trading Accounts and Deposits

 

Cash held in trading accounts may be unavailable at times for immediate withdrawal depending upon trading activity. Cash needed to meet credit requirements and that was available for immediate withdrawal as of March 31, 2013 and December 31, 2012 was as follows:

 

   March 31,  December 31,
   2013  2012
Credit requirement  $4,365,005   $3,445,912 
Available credit   9,074,932    8,579,111 
Trading accounts and deposits  $13,439,937   $12,025,023 

 

Revenue Recognition

 

Wholesale Energy Trading

 

The Company derives revenues from trading financial and physical energy contracts. These contracts are marked to fair value each period in the accompanying consolidated balance sheets and revenues, net of costs, are recorded based on realized and unrealized gains and losses. These transactions are shown as operating activities in the consolidated statements of cash flow.

 

The Company’s wholesale trading activities also use derivatives such as swaps, forward sales contracts, futures contracts, and options to generate trading revenues and its retail activities may use such instruments to hedge the cost of energy acquired to service customers.

 

13
 

 

The Company’s agreements with the ISO’s, ICE, and NGX 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. Substantially all the Company’s wholesale revenues are generated by these trading activities.

 

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.

 

Commodity Derivative Instruments

 

Objectives for Utilization of Derivative Instruments

 

In its businesses, the Company is exposed to risk due to changes in commodity prices, interest rates, foreign exchange rates, and credit quality. We manage some of these risks using derivative instruments and account for them in accordance with ASC 815, Derivatives and Hedging (“ASC 815”). ASC 815 requires all derivatives to be recorded on the balance sheet at fair value.

 

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 business, the Company is exposed to volatility in the cost of energy acquired for sale to customers, and as a result, we may use 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.

 

Accounting for Derivative Instruments and Their Impact on Our Financial Statements

 

In our wholesale energy trading operations, all realized and unrealized gains and losses on derivative instruments are recorded in revenues.

 

Our retail operations follow the 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 hedge relationships must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis.

 

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. 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.

 

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For the fourth quarter of 2012, the Company hedged the cost of 5,120 MWh or 54% of the 9,477 MWh of electricity sold to its retail customers in such period.

 

As of December 31, 2012, we had hedged the cost of 22,160 MWh (approximately 37% of expected 2013 electricity purchases for the customers receiving service from us as of that date) and $82,032 of the loss on the effective portion of the hedge was deferred and included in accumulated other comprehensive income (“AOCI”). During the three months ended March 31, 2013, $425,703 of accumulated gains on the hedge were reclassified to cost of energy sold.

 

For the first quarter of 2013, the Company hedged the cost of 15,925 MWh or 83% of the 19,099 MWh of electricity sold to its retail customers in such period.

 

As of March 31, 2013, we had hedged the cost of 71,360 MWh (approximately 70% of expected electricity purchases for the remainder of 2013) and $49,061 of the gain on the effective portion of the hedge was deferred and included in AOCI. This amount is expected to be reclassified to cost of energy sold by December 31, 2013.

 

The following table lists the fair values of the Company’s derivative assets and liabilities as of March 31, 2013 and December 31, 2012:

 

      Fair Value 
   Balance
Sheet
Classification
   Asset
Derivatives
    Liability
Derivatives
 
At March 31, 2013             
Designated as cash flow hedging instruments:             
Energy commodity contracts  Trading accounts and deposits  $213,640   $164,579 
              
Not designated as hedging instruments:             
Energy commodity contracts  Trading accounts and deposits   71,576    17,223 
Total derivative instruments      285,216    181,802 
Cash in collateral and deposit accounts  Trading accounts and deposits   13,336,523     
Trading accounts and deposits, net     $13,621,739   $181,802 

 

At December 31, 2012             
Designated as cash flow hedging instruments:             
Energy commodity contracts  Trading accounts and deposits  $63,571   $158,880 
              
Not designated as hedging instruments:             
Energy commodity contracts  Trading accounts and deposits   99,264    12,264 
Total derivative instruments      162,835    171,144 
Cash in collateral and deposit accounts  Trading accounts and deposits   12,033,332     
Trading accounts and deposits, net     $12,196,167   $171,144 

 

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:


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Period/Derivative  Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) 

Income Statement

Classification

  Gain (Loss) Reclassified from AOCI to Income (Effective Portion)
Three Months Ended March 31, 2013             
Cash flow hedge  $49,061   Cost of energy sold  $425,703 
             
Year Ended December 31, 2012             
Cash flow hedge  $(82,032)  Cost of energy sold  $5,683 

 

Accumulated Other Comprehensive Income

 

The following table provides details with respect to changes in accumulated other comprehensive income as presented in our consolidated balance sheets, including those relating to our designated cash flow hedges, for the period from January 1, 2013 to March 31, 2013:

 

   Foreign
Currency
Cash Flow
Hedges
  Total
Balance - December 31, 2012  $539,311   $(82,032)  $457,279 
Other comprehensive income before reclassifications   (37,074)   638,828   (331,684)
Amounts reclassified from AOCI       (425,703)   425,703 
Net current period other comprehensive income   (37,074)   131,093    94,019 
Balance - March 31, 2013  $502,237   $49,061   $551,298 

 

Deferred Financing Costs

 

Prior to the May 10, 2012 effective date of its Notes Offering, 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 Subordinated Notes sold, exclusive of any expected renewals. Deferred financing costs, net as of March 31, 2013 and December 31, 2012 were as follows:
 

   March 31,  December 31,
   2013  2012
Deferred financing costs  $393,990   $393,990 
Less: accumulated amortization   (10,667)   (5,011)
Deferred financing costs, net  $383,323   $388,979 

 

Total amortization for the three months ended March 31, 2013 and year ended December 31, 2012 was $5,656 and $5,011, respectively and is included in other general and administrative expenses.

 

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Foreign Currency Translation

 

For foreign subsidiaries whose functional currency is the local foreign currency, 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 denominated in a foreign currency 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 a gain of $246 for the three months ended March 31, 2013 and a loss of $8,639 for the three months ended March 31, 2012.

 

Accounts Receivable - Trade

 

Accounts receivable – trade consists of receivables from both our wholesale trading and retail segments. Wholesale trading receivables represent net settlement amounts due from a market operator or an exchange while those from retail include amounts resulting from sales to end-use customers.

 

   March 31,  December 31,
   2013  2012
Wholesale trading  $359,038   $1,756,926 
Retail energy services - billed   475,104    235,996 
Retail energy services - unbilled   278,699    198,345 
Accounts receivable - trade  $1,112,841   $2,191,267 

 

All 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. There was no allowance for doubtful accounts as of March 31, 2013 or December 31, 2012.

 

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 and 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 months ended March 31, 2013 and 2012, the Company included $1,474,405 and $842,202, respectively, in compensation and related expenses, representing the allocation of profits interests to Class B members.

 

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. In addition, transaction costs are expensed as incurred.

 

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Income Taxes

 

Except for CAN, the Company’s subsidiaries are not taxable entities for federal income tax purposes. As such, the Company does 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.

 

CAN 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 2008 through 2012 and its Canadian tax returns are potentially open to examination for the years 2009 through 2012.

 

On November 12, 2012, a letter from the Minnesota Department of Revenue was received notifying the Company that TCP’s 2009, 2010, and 2011 returns are under review by the Department.

 

Recent Accounting Pronouncements

 

Effective January 1, 2013, the Company adopted ASU No. 2013-03, Comprehensive Income (Topic 220), Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required that provide additional detail about those amounts.

 

In March 2013, the FASB issued ASU No. 2013-05, Foreign Currency Matters (Topic 830), Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity. This ASU clarifies the applicable guidance for the release of the cumulative translation adjustment for entities that cease to hold a controlling financial interest in a subsidiary or group of assets within a foreign entity when the subsidiary or group of assets is a nonprofit activity or a business and there is a cumulative translation adjustment balance associated with that foreign entity. The standard also affects entities that lose a controlling financial interest in an investment in a foreign entity by sale or other transfer event and those that acquire a business in stages. Under the new guidance, the cumulative translation adjustment is released into net income only if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided. The new guidance is effective prospectively for fiscal years beginning after December 15, 2013. While this guidance does not currently apply to the Company’s financial statements, it may in the future.

 

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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.

 

3.Segment Information

 

Commencing with the third quarter of 2012, the Company has two business segments used to measure its business activity – wholesale trading and retail energy services. Wholesale trading activities entail trading financial and derivative electricity in wholesale markets while retail energy services sells physical electricity to residential and small commercial customers. 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. For the first quarter of 2013, there were no internal transactions between segments. Information on segments as of and for the three month period ended March 31, 2013 is as follows:

 

   Wholesale
Energy
Trading
  Retail
Energy
Services
  Corporate  Eliminations  Consolidated Total
Three Months Ended               
Ended March 31, 2013               
Revenues*  $6,797,068   $1,437,329   $1,197,211   $(1,197,211)  $8,234,397 
Costs of retail electricity sold       1,684,382            1,684,382 
Retail sales & marketing       388            388 
Compensation & benefits   3,113,813    41,561    445,238        3,600,612 
Professional fees   604,944    49,518    272,726        927,188 
Other general & administrative   1,100,270    257,577    471,416    (1,197,211)   632,052 
Trading tools & subscriptions   209,336    5,453    7,831        222,620 
Operating costs & expenses   5,028,363    2,038,879    1,197,211    (1,197,211)   7,067,242 
Operating income (loss)  $1,768,705   $(601,550)  $   $   $1,167,155 
Capital expenditures  $16,548   $   $11,326   $   $27,874 
                          
At March 31, 2013                         
Identifiable Assets                         
Cash  $   $   $1,010,418   $   $1,010,418 
Trading accounts & deposits   12,524,937    915,000            13,439,937 
Accounts receivable - trade   359,038    753,803            1,112,841 
Prepaid expenses & other assets   196,632    39,920    102,638        339,190 
Total current assets   13,080,607    1,708,723    1,113,056        15,902,386 
                          
Equipment & furniture, net   90,368    5,449    454,589        550,406 
Intangible assets, net       107,989    437,500        545,489 
Deferred financing costs, net           383,323        383,323 
Total assets  $13,170,975   $1,822,161   $2,388,468   $   $17,381,604 

 

 

* Wholesale Energy Trading revenue is net of costs.

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4.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, fair value risk, and credit risk.

 

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

 

The fair values of the Company’s cash, accounts receivable, and accounts payable were considered to approximate their carrying values at March 31, 2013 and December 31, 2012 due to the immediate and short-term nature of the accounts. The fair value of related party notes payable may be different from their carrying values. No assessment of the fair value of these obligations has been completed and there is no readily available market price. However, management believes that the carrying values are a reasonable approximation of fair value at March 31, 2013 and December 31, 2012.

 

Management believes the carrying values of the Company’s notes payable, renewable unsecured subordinated notes, and redeemable preferred units reasonably approximate their fair values at March 31, 2013 and December 31, 2012 due to the relatively new age of these particular instruments.

 

5.Concentrations of Credit Risk

 

Financial instruments that subject the Company to concentrations of credit risk consist principally of trading accounts and deposits and accounts receivable. At any given time there may be a concentration of receivables balances with one or more of the exchanges upon which transact our wholesale business or, in the case of retail, one or more of the utilities operating in POR states in which we do business.

 

As of March 31, 2013, there were three accounts with a receivable balance greater than 10% that aggregated 83% of total consolidated accounts receivable.

 

As of December 31, 2012, there were two accounts with receivable balances greater than 10% that together aggregated 95% of total consolidated accounts receivable.

 

The Company believes that any risk associated with these concentrations would be minimal, if any.

 

6.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 levels of 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 in active markets that are observable for the asset or liability, either directly or indirectly.
·Level 3 inputs are unobservable inputs for which little or no market data exists.

 

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the valuation methods are considered appropriate and consistent with those used by other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

 

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Determination of fair value for electricity derivative contracts is complex and relies on judgments concerning future prices, volatility, and liquidity, among other factors. All of the derivatives traded by the Company are traded on exchanges with quoted market prices for identical instruments. There have been no changes in the methodologies used since December 31, 2012.

 

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

 

   Level 1  Level 2  Level 3  Total
March 31, 2013                    
Trading accounts and deposits  $13,439,937   $   $   $13,439,937 
                     
December 31, 2012                    
Trading accounts and deposits  $12,025,023   $   $   $12,025,023 

 

 

7.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 was been re-named “Town Square Energy” and is run as a division of TCP, although in March 2013, TCP began the process of reorganizing TSE as a separate wholly-owned 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 Company’s assessment of the fair values of these assets was based on significant inputs that are not observable in quoted markets and thus represent a Level 3 measurement as defined in ASC 820. The fair value of the service contract was based on the replacement price and will be amortized over twenty-three months, its useful life, using the straight-line method. Customer relationships were valued using a variation of the income approach. Under this approach, the present value of expected future cash flows resulting from the relationships is used to determine the fair value which will be amortized over a three year period using the straight-line method.

 

Effective January 1, 2013, in connection with the private sale of his units to Mr. Krieger, the Company entered into a Non-Competition Agreement 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.

 

As of March 31, 2013 and December 31, 2012, intangible assets consisted of the following:

 

   March 31,  December 31,
   2013  2012
Acquisition of CP&U  $160,000   $160,000 
Non-competition agreement   500,000     
Less: accumulated amortization   (114,511)   (34,674)
Intangible assets, net  $545,489   $125,326 

 

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Total amortization for the three months ended March 31, 2013 and 2012 was $79,837 and $0, respectively and is included in other general and administrative expenses.

 

8.Debt

 

Notes payable by the Company are summarized as follows:

 

   March 31,  December 31,
   2013  2012
Note payable to HTS (as defined below), dated October 1, 2011, quarterly payments of principal of $485,751 plus interest at 15% per annum until maturity on October 1, 2013 with a balloon principal payment of $1,943,004.  $3,400,257   $3,400,262 
           
Note payable to John O. Hanson, a related party, dated April 8, 2011, accruing interest at 20%. The loan is payable on demand or on June 30, 2013.   200,000    200,000 
           
Note payable to Patrick C. Sunseri, an employee and related party, dated July 16, 2009, monthly payments of $166,667 plus interest at 15% per annum until April 1, 2013. This note is secured by all cash, accounts receivable, and other assets of TCP and is personally guaranteed by one member of TCPH.   166,667    666,665 
           
Renewable Unsecured Subordinated Notes, see below.   3,037,689    2,013,138 
   $6,804,613   $6,280,065 

 

Notes payable by maturity are summarized as follows:


   March 31,  December 31,
   2013  2012
 2013 or on demand   $4,664,344   $5,005,620 
 2014 to March 31    284,580     
 Current maturities    4,948,924    5,005,620 
             
 2014 after March 31    449,014    283,500 
 2015    408,700    350,690 
 2016    219,920    193,500 
 2017    608,055    281,755 
 2018 & thereafter    170,000    165,000 
 Long term debt    1,855,689    1,274,445 
 Total   $6,804,613   $6,280,065 

 

The 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.

 

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As of March 31, 2013, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants. See Borrowings from HTS for certain restrictions on the Margin Agreement not imposed by ABN AMRO, but in connection with an amendment to the HTS Note as defined below.

 

Borrowings from HTS

 

Between 2006 and 2010, TCP borrowed a total of $30,800,000 from the HTS Parties. HTS was a member of the Company and a related party until March 23, 2011 when its membership interests were re-purchased by the Company.

 

In May 2010, the HTS Parties called the loans, the outstanding balance of which was $28,550,000 as of December 31, 2010. On March 11, 2011 the parties reached a Settlement Agreement that defined terms of repayment, as well as provided for a binding arbitration procedure to resolve other outstanding disputes. By July 1, 2011, the Company had repaid the entire principal balance outstanding, paid accrued interest of $1,640,958, and reduced the HTS Parties capital account balance by a payment of $1,000,000. Following resolution of the dispute between the HTS Parties and the Company, all amounts owed to the HTS Parties as of September 30, 2011, including the HTS Parties’ remaining capital account balance, unpaid interest, and legal fees were converted into a new $5,829,017 note dated October 1, 2011 (the “HTS Note”).

 

The HTS Note contains certain affirmative and negative covenants including delivery of quarterly and annual financial statements and annual tax returns, maintenance of business, and restrictions on additional indebtedness, as well as specifying certain events of default. The HTS Note is jointly and severally guaranteed as to payment of up to $3,711,486 by Timothy Krieger and Michael Tufte. Initially, the HTS Note was payable in twelve equal quarterly installments of principal of $485,751 plus interest at 15% per annum until maturity on October 1, 2014. However, on February 20, 2012, the HTS Note was amended to accommodate the Margin Agreement as follows:

 

·CEF may not draw more than $7,000,000 until the Note is paid in full;
·CEF must maintain not less than $3,000,000 in its ABN AMRO account;
·The Company shall retain as capital all funds drawn under the Margin Agreement until the HTS Note is paid in full;
·The Company shall not distribute to its members, directly or indirectly, any of the proceeds of the Margin Agreement;
·The Company shall maintain a separate accounting with respect to the withdrawal and use of funds; and
·The maturity date of the HTS Note was shortened by one year to October 1, 2013, and consequently, the Company shall make a balloon principal payment of $1,943,004 at maturity.

 

As of March 31, 2013 and December 31, 2012, the Company was in compliance with all covenants with respect to the HTS Note.

 

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Related Party Indebtedness

 

On September 1, 2006, April 1, 2008, and April 8, 2011, TCP and its predecessor entered into certain borrowing arrangements with John O. Hanson, all accruing interest at an annual rate of 20%. As of December 31, 2011, the total amount owed to Mr. Hanson was $2,945,000. Effective January 31, 2012, TCP sold new issue redeemable preferred units to Mr. Hanson for a purchase price of $2,745,000, paid by conversion of debt, and Mr. Hanson became a related party. Effective July 1, 2012, Mr. Hanson’s preferred units in TCP were exchanged for preferred units issued by the Company with identical financial rights and terms. As a result of these transactions, as of December 31, 2012, the Company owed Mr. Hanson $200,000 and he owned 496 redeemable preferred units with a book value of $2,745,000. See Note 9. Ownership.

 

As of March 31, 2013 and December 31, 2012, the Company was in compliance with all covenants with respect to its obligations to Mr. Hanson.

 

On May 21, 2012, TCP and Patrick C. Sunseri entered into a First Amendment to the Loan Agreement, Secured Promissory Note, and Security Agreement dated July 16, 2009 (the “Sunseri Loan”). The Amendment changes the annual interest rate to the lower of 15% or the highest rate permitted by law, provides for the repayment of the Loan’s principal and interest over a twelve month period beginning May 1, 2012, adds TCPH as a corporate guarantor with respect to TCP’s obligations to Mr. Sunseri, and adds certain financial covenants and events of default.

 

At March 31, 2013 and December 31, 2012, the Company was not in compliance with all of the covenants on the Sunseri Loan and they were not enforced by the lender. Moreover, none of the technical defaults were waived as the Company did not seek waiver. The note was paid in full on April 1, 2013.

 

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 and the Company made interest payments during the three months ended March 31, 2013 and year ended December 31, 2012 of $36,940 and $16,857, respectively. Total accrued interest on the Subordinated Notes at March 31, 2013 and December 31, 2012 was $98,454 and $50,553, respectively.

 

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As of March 31, 2013, the Company had $3,037,689 of its Subordinated Notes outstanding as follows:

 

Initial Term  Principal Amount  Weighted Average Interest Rate
3 months  $195,741    15.77%
6 months   83,206    7.43%
1 year   848,056    10.61%
2 years   449,010    11.79%
3 years   463,700    12.82%
4 years   219,920    13.75%
5 years   608,055    15.08%
10 years   170,000    13.65%
Total  $3,037,689    12.66%
Weighted average term   35.0 mos      

 

9.Ownership

 

Effective January 31, 2012, TCP, a wholly-owned subsidiary of the Company, sold certain financial rights to 496 of its new issue units to John O. Hanson for a purchase price of $2,745,000, paid by conversion of certain notes payable to him. These redeemable preferred membership units (the “preferred units”) are cumulative and incorporate a defined return, are not convertible, and have no corporate governance rights. Holders of the common units control all corporate governance rights and own the residual financial interest.

 

From the effective date to the redemption date, TCP shall make a guaranteed payment or distribution of $45,750 per month to Mr. Hanson or his designee. At any time prior to December 31, 2013, TCP may repurchase the preferred units for the sum of $2,745,000. If TCP does not repurchase the preferred units prior to such date, Mr. Hanson may require Timothy S. Krieger, TCP’s Chief Executive Officer, to purchase the preferred units on such date. Should TCP default on its obligations to Mr. Hanson, payment of all specified amounts has been personally guaranteed by Mr. Krieger.

 

Effective July 1, 2012, Mr. Hanson’s preferred units in TCP were exchanged for preferred units issued by the Company with identical financial rights and terms.

 

Pursuant to a Membership Unit Purchase Agreement dated December 31, 2012, Mr. Krieger purchased the 525 units held by DBJ 2001 Holdings, LLC, which is controlled by Mr. Johnson, a director of the Company.

 

The Company’s ownership as of March 31, 2013 is summarized below:

 

   Redeemable Preferred  Common
   Units held  Percent of class  Units held  Percent of class
John O. Hanson   496    100.00%       0.00%
Timothy S. Krieger       0.00%   4,960    100.00%
Total   496    100.00%   4,960    100.00%

 

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10.Related Party Transactions

 

The following table summarizes notes payable to related parties at March 31, 2013 and December 31, 2012:

 

   March 31,  December 31,
   2013  2012
John O. Hanson, owner of redeemable preferred units  $200,000   $200,000 
Patrick C. Sunseri, an employee   166,667    666,665 
   $366,667   $866,665 

 

Interest expense associated with related party notes was $21,577 and $81,147 for the three months ended March 31, 2013 and 2012, respectively.

 

On June 23, 2011, the building in which the Company leases its Lakeville, Minnesota office space was sold to Kenyon Holdings, LLC (“Kenyon”), a company owned by Timothy S. Krieger, the Company’s Chief Executive Officer and controlling member and Keith W. Sperbeck, its Vice President of Operations. The existing lease with the Company was assumed from the previous owner by Kenyon, pursuant to which the Company is required to pay base rent, real estate taxes, and operating expenses. On November 21, 2011, the Company amended the lease, increasing the amount of rented space from 6,378 to 8,333 square feet, increasing the monthly rent from $7,972 to $10,416, and extending the lease term by two years and three months. On January 1, 2013, the Company and Kenyon entered into a new five year lease replacing the old lease and the addenda thereto. The new lease expires December 31, 2017 and is for 11,910 square feet at a monthly rent of $12,264.

 

During the three months ended March 31, 2013 and 2012, $52,720 and $35,988 was paid to Kenyon for rent, real estate taxes, and operating expenses.

 

Effective January 1, 2013, in connection with the purchase of David B. Johnson’s units by Mr. Kreiger, the Company entered in a Non-Competition Agreement 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 twenty-four equal monthly installments of $20,833 each.

 

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.

 

11.Commitments and Contingencies

 

FERC Investigation

 

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. Depending on the investigation’s outcome, the Company may be liable for legal fees, potential disgorgement of profits, and possible civil penalties. Since the investigation is still ongoing, the Company is unable to determine the likelihood of an unfavorable outcome or the amount or range of any potential loss, other than the expenditure of legal fees for defense, which are being expensed as incurred.

 

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Former Employee Litigation

 

On February 1, 2011, the Company commenced a major restructuring of the operations of CAN and all personnel were terminated, although several were subsequently re-hired. During the course of 2011, three former employees commenced legal proceedings and brought separate summary judgment applications seeking damages aggregating C$3,367,000 for wrongful dismissal and payment of performance bonuses. One former employee sought and obtained an injunction to freeze certain bank accounts utilized by CAN containing approximately C$1,814,000. Although the initial injunction was set aside, another former employee obtained an attachment order and the funds remained in trust. The Company filed counterclaims aggregating C$3,096,000 against two 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. The Company reduced its accrual related to the litigation by C$775,024 during the first quarter. On April 2, 2012, the Company won its appeal of the attachment order and the funds in trust were released. The total returned was C$1,829,000. 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 CAN for a portion of the claim amounting to C$1,376,726. The remainder of the allowed application was ordered to be assessed at a trial. The Company has appealed the allowed application to the Alberta Court of Appeal and the matter is scheduled to be heard June 13, 2013.

 

Although it is management’s opinion that the ultimate resolution of the litigation arising as a result of the reorganization of CAN will not have a material effect on its financial position, results of operations, or liquidity, it is possible that this assessment could change by an amount that could be material. 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 Resettlement

 

On May 11, 2012, the 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. On June 15, 2012 the Company filed a motion for stay pending appeal to FERC; the stay request was denied on July 3, 2012. The Company also filed a stay pending appeal with the U.S. Court of Appeals on June 27, 2012; on July 6, 2012 this request was also denied. Consequently, pursuant to the May 11, 2012 order, the Company was required to return $782,000 to PJM. This amount was included in accounts payable as of June 30, 2012 and 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. The due date for intervention in this proceeding was August 8, 2012 and certain subsidiaries of TCPH filed motions to intervene in this proceeding as they were not named parties. The case is currently being briefed before the Court of Appeals and final briefs were filed at the end of 2012. Oral argument in this appeal occurred on April 16, 2013. If FERC’s order is overturned on appeal, 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 appeals process, the Company is presently unable to determine a reasonable estimate of the amount, if any, that could be returned.

 

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Guarantees

 

TCPH has provided guarantees for the future obligations of TCP, SUM, and CEF with respect to their participation in PJM of an unlimited amount and up to $7,000,000 for each of MISO and ERCOT.

 

The Company has also guaranteed payment of TCP’s obligations with respect to the Sunseri loan, which was paid in full on April 1, 2013.

 

12.Subsequent Events

 

From April 1, 2013 to May 12, 2013, the Company sold additional Subordinated Notes totaling $1,189,012 with a weighted average term of 34.1 months and bearing a weighted average interest rate of 13.7%.

 

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 2012 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 6, “Item 1A – Risk Factors” of our 2012 Form 10-K, and the “Risk Factors” section beginning on page 10 of our Form S-1.

 

The risks and uncertainties described in this Form 10-Q, our 2012 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.

 

Today, the electric power industry in the U.S. includes any entity producing, selling, or distributing electricity. At the end of 2011, industry participants included 214 investor-owned, 1,949 publicly-owned, 924 cooperative, and 23 federal utilities1. Additionally, non-utility power producers include both independent power producers and customer-owned generation facilities. Wholesale power market participants include banks, hedge funds, private equity firms, and proprietary trading houses. Regulated power marketers and energy service providers do not own any generation but buy and sell in wholesale and retail markets. About 770 energy service providers are licensed by the states that allow retail choice.

 

Overall, according to EIA data for 2011, the U.S. electric power industry sold 3,750 GWh at retail (down 0.1% from 2010) for a little more than $371 billion (up 0.6%) to over 144 million residential, commercial, industrial, and transportation customers (up 0.3%). In 2011, the average U.S. retail electricity price was 9.81¢/kWh - residential customers paid 11.51¢/kWh, commercial users paid 9.84¢/kWh, and industrial and transportation consumers paid 6.54¢/kWh.

 

The investor-owned portion of the industry, which accounts for the majority of customers, unit sales, and revenues - 71.1%, 68.9%, and 70.0%, respectively in 2011 - has been undergoing a massive restructuring process since the passage by Congress of the Public Utilities Regulatory Policy Act of 1978.

 

 

 


1Source is the EIA’s Electric Sales, Revenue, and Average Price report with data for 2011 released September 27, 2012, next release date, September, 2013

 

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PURPA stimulated development of renewable energy sources and co-generation and laid the groundwork for deregulation and competition by opening wholesale power markets to non-utility producers of electricity for the first time.

 

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 consumer pricing is 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.

 

In general, retail electricity bills include three major components – generation costs, delivery services, and governmental policies. Generation charges cover the costs of power plant fuel, operations, maintenance, and capital. Delivery charges recover the costs to operate and maintain power transmission and distribution systems. Policy costs include federal and state government-mandated programs such as universal and lifeline service, renewable energy and energy efficiency programs, and sales and use taxes.

 

Generation and transmission and distribution charges are retained by the industry as a whole while policy charges are passed through to federal and state authorities. 2011’s average retail price included generation costs of 5.70¢/kWh (58%), distribution expenses of 3.00¢/kWh (31%), and transmission charges of 1.10¢/kWh (11%). Of course, these costs and percentages fluctuate from year to year and from state to state, primarily due to wholesale energy market conditions.

 

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.

 

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FERC’s U.S. Wholesale Electricity Markets

 

 

 

 

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.

 

31
 

 

Trading activity in most ISOs occurs between the market operator and registered participants, that is, it is centrally cleared, and is often characterized by the acquisition of electricity at a given location such as a node or hub and its delivery to another. Financial or “virtual” 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 electricity itself with the ISO accepting payment and passing it on to the generator. In general, trading physical energy requires more capital than financial trades since electricity must be purchased and paid for in a week or so, while the corresponding receivable may not be collected for as long as 60 days. In any case, participants are typically required to place cash collateral with market operators, with the specific amounts depending upon the rules of the particular market.

 

In addition to the markets operated by the ISOs, derivative financial contracts such as swaps, options, and futures contracts 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.

 

Retail Electricity Markets

 

Today, consumers in 18 states and the District of Columbia have some form of choice in their electric power supplier as shown by the following map:


 

 

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In the 1990s, states in the Northeast and California where retail prices were historically among the highest in the country began restructuring their investor-owned electric power industries in an effort to bring the benefits of competition to retail customers. Massachusetts and Rhode Island became the first states to effectively implement choice in 1998.

 

This new regulatory approach centered on deregulation of generation and retail marketing functions while continuing the traditional cost-of-service method for transmission and distribution service providers, now known as electric distribution companies (each an “EDC”). EDCs are responsible for delivering power, billing consumers, and resolving service issues, but customers are free to purchase their energy from any licensed supplier operating in the state. For example, a typical residential service bill for 778 kWh from United Illuminating (one of two EDCs operating in Connecticut) for the month from August 9 to September 7, 2011 totaled $153.02 or 19.67¢/kWh. The bill included:

 

Charge  Paid to  Cost
(cents/kWh)
  Dollar
amount
  Percent
of total
Generation  Electricity supplier   8.65   $67.30    44.0%
Delivery  EDC   7.93    61.70    40.3%
Transition (note 1)  EDC   1.52    11.84    7.7%
Policy  Governmental authorities   1.57    12.18    8.0%
Total      19.67   $153.02    100.0%

 

 

Note

1 - Transition charges include costs associated with moving from a regulated market to a restructured one and allow EDCs to recapture past prudent investments in divested generation assets as approved by a public utilities commission ("stranded costs") that would otherwise be unrecoverable after deregulation. 

Source

United Illuminating web site, accessed May 5, 2011    

 

 

Company Overview

 

TCPH was formed as a Minnesota limited liability company on December 30, 2009. On December 31, 2011, TCPH received all of the outstanding membership interests of TCP, CP, and TCE in exchange for issuing ownership interests in TCPH. Through these subsidiaries, we trade financial and physical electricity contracts in North American wholesale markets regulated by FERC and operated by ISOs and RTOs and energy derivative contracts on exchanges regulated by the CFTC, including ICE, NGX, and CME.

 

The Company is also authorized by DOE to export electricity to Canada, is licensed by the states of Connecticut, Massachusetts, and Rhode Island as an electric supplier to retail customers (operations have yet to begin in Massachusetts and Rhode Island), and has a retail electric supplier license application pending in New Hampshire.

 

Wholesale Energy Trading

 

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. However, our revenue is limited to some extent by the amount of collateral we have posted with a market operator or exchange. Our primary costs in generating revenue are compensation of our energy traders as well as the costs of obtaining capital necessary to post collateral.

 

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During the three months ended March 31, 2013 and 2012, 100% of our trading volume in FERC-regulated markets was financial electricity, that is, we traded no physical power.

 

The tables below detail our open derivative contracts held for trading purposes as of the dates indicated:

 

Open Derivative Contracts Held for Trading


As of March 31, 2013


Contract     Contract  Contract Dates  Number of  Fair Value
Type  Commodity  Hub  Start  End  Settlement  Lots  Asset  Liability
Future  Electricity  MISO Indiana Hub   Daily    Daily    Daily    9   $12,400   $1,904 
Future  Electricity  PJM West Hub   Daily    Daily    Daily    27    44,032    2,160 
Future  Electricity  MISO Indiana Hub off peak   Daily    Daily    Daily    48    13,944    600 
Future  Electricity  PJM AD Hub   Daily    Daily    Daily    1    1,200     
Future  Electricity  PJM West Hub off peak   Daily    Daily    Daily    24        4,180 
Future  Electricity  NEPOOL Mass Hub   04/01/13    04/30/13    05/05/13    330         2,024 
Future  Natural gas  Henry Hub   05/01/13    05/31/13    04/27/13    31        6,355 
Totals                            $71,576   $17,223 

 

As of December 31, 2012


Contract     Contract   Contract Dates   Number of    Fair Value 
Type  Commodity  Hub   Start    End    Settlement   Lots   Asset    Liability 
Future  Electricity  MISO Indiana Hub   Daily    Daily    Daily    14   $15,704   $4,568 
Future  Electricity  PJM West Hub   Daily    Daily    Daily    82    83,560    1,904 
Future  Electricity  MISO Indiana Hub off peak   Daily    Daily    Daily    32        5,792 
Totals                            $99,264   $12,264 

 

Retail Energy Services

 

We entered the retail energy services business on June 29, 2012 via the CP&U/TSE transaction. Beginning in July 2012, we started selling electricity purchased on ISO-NE, the New England wholesale market, to both residential and small commercial customers in Connecticut. We primarily use direct marketing strategies to sell our services and our customers may typically cancel their contracts at any time.

 

In our retail business, we are exposed to volatility in the cost of the energy acquired for sale to customers and we have designated the derivative contracts detailed below as cash flow hedges for a portion of our expected 2013 cash power purchases for retail.

 

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Open Derivative Contracts Designated as Cash Flow Hedges


As of March 31, 2013


Contract  Contract   Delivery    On Peak/ Off Peak Hours in    Load    Energy    Wtd Avg Price     Fair Value 
Type Hub     Month       Month       (MW)       (MWh)     ($/MWh)    Asset    Liability 

Electricity future  ISO-NE Mass Hub on peak   Apr 2013    352    15    5,280   $52.28   $   $12,936 
Electricity future  ISO-NE Mass Hub on peak   May 2013    352    10    3,520    52.28        18,392 
Electricity future  ISO-NE Mass Hub on peak   Jun 2013    320    10    3,200    52.28    14,800     
Electricity future  ISO-NE Mass Hub on peak   Jul 2013    352    15    5,280    53.77    36,256     
Electricity future  ISO-NE Mass Hub on peak   Aug 2013    352    15    5,280    53.77    11,968     
Electricity future  ISO-NE Mass Hub on peak   Sep 2013    320    10    3,200    52.28        18,960 
Electricity future  ISO-NE Mass Hub on peak   Oct 2013    368    10    3,680    52.28        26,404 
Electricity future  ISO-NE Mass Hub on peak   Nov 2013    320    10    3,200    52.28        2,160 
Electricity future  ISO-NE Mass Hub on peak   Dec 2013    336    10    3,360    52.28    75,180     
Electricity future  ISO-NE Mass Hub off peak   Apr 2013    368    5    1,840    43.68        9,108 
Electricity future  ISO-NE Mass Hub off peak   May 2013    392    5    1,960    40.65        21,266 
Electricity future  ISO-NE Mass Hub off peak   Jun 2013    400    5    2,000    40.65        1,700 
Electricity future  ISO-NE Mass Hub off peak   Jul 2013    392    5    1,960    40.65    1,078     
Electricity future  ISO-NE Mass Hub off peak   Aug 2013    392    5    1,960    40.65        8,330 
Electricity future  ISO-NE Mass Hub off peak   Sep 2013    400    5    2,000    40.65        20,100 
Electricity future  ISO-NE Mass Hub off peak   Oct 2013    376    5    1,880    40.65        21,714 
Electricity future  ISO-NE Mass Hub off peak   Nov 2013    400    5    2,000    40.65        3,509 
Electricity future  ISO-NE Mass Hub off peak   Dec 2013    408    5    2,040    40.65    74,358     
Totals                     53,640   $48.85   $213,640   $164,579 

 

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Open Derivative Contracts Designated as Cash Flow Hedges


As of December 31, 2012


 

Contract  Contract   Delivery    On Peak/ Off Peak Hours in    Load    Energy    Wtd Avg Price    Fair Value 
Type  Hub    Month     Month     (MW)     (MWh)     ($/MWh)    Asset    Liability 

Electricity future  ISO-NE Mass Hub on peak   Jan 2013    352    10    3,520   $71.13   $32,331   $ 
Electricity future  ISO-NE Mass Hub on peak   Feb 2013    320    5    1,600    67.38    15,280     
Electricity future  ISO-NE Mass Hub on peak   Mar 2013    336    5    1,680    52.28        5,208 
Electricity future  ISO-NE Mass Hub on peak   Apr 2013    352    5    1,760    52.28        22,440 
Electricity future  ISO-NE Mass Hub on peak   May 2013    352    5    1,760    52.28        30,008 
Electricity future  ISO-NE Mass Hub on peak   Jun 2013    320    5    1,600    52.28        22,320 
Electricity future  ISO-NE Mass Hub on peak   Jul 2013    352    5    1,760    52.28        7,040 
Electricity future  ISO-NE Mass Hub on peak   Aug 2013    352    5    1,760    52.28        13,200 
Electricity future  ISO-NE Mass Hub on peak   Sep 2013    320    5    1,600    52.28        23,120 
Electricity future  ISO-NE Mass Hub on peak   Oct 2013    368    5    1,840    52.28        25,944 
Electricity future  ISO-NE Mass Hub on peak   Nov 2013    320    5    1,600    52.28        9,600 
Electricity future  ISO-NE Mass Hub on peak   Dec 2013    336    5    1,680    52.28    15,960     
Totals                     22,160   $56.36   $63,571   $$158,880 

 

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Results of Operations

 

Three Months Ended March 31, 2013 and 2012

 

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 March 31,
Dollars in thousands  2013  2012  Increase (decrease)
   Dollars  Percent  Dollars  Percent  Dollars  Percent
Revenue                              
Wholesale trading revenue, net  $6,797    82.5%  $3,813    100.0%  $2,984    78.3%
Retail electricity revenue   1,437    17.5%       0.0%   1,437    na   
Net revenue   8,234    100.0%   3,813    100.0%   4,421    115.9%
Operating costs & expenses                              
Cost of retail electricity sold   1,684    20.5%       0.0%   1,684    na   
Retail sales & marketing       0.0%       0.0%       na   
Compensation & benefits   3,601    43.7%   2,101    55.1%   1,501    71.4%
Professional fees   927    11.3%   625    16.4%   302    48.3%
Other general & administrative   632    7.7%   344    9.0%   288    83.9%
Trading tools & subscriptions   223    2.7%   202    5.3%   21    10.4%
Total operating expenses   7,067    85.8%   3,271    85.8%   3,796    116.0%
Operating income   1,167    14.2%   542    14.2%   625    115.4%
Interest expense   (349)   -4.2%   (365)   -9.6%   17    -4.5%
Interest income   7    0.1%   10    0.2%   (3)   -26.3%
Loss on foreign currency exchange       0.0%   (9)   -0.2%   9    -100.0%
Other income expense, net   (342)   -4.1%   (365)   -9.6%   23    -6.3%
Income before income taxes   827    10.0%   177    4.7%   649    365.9%
Income tax provision (benefit)       0.0%   37    1.0%   (37)   -100.0%
Net income   827    10.0%   140    3.7%   686    488.7%
Preferred distributions   (137)   -1.7%   (92)   -2.4%   (45)   49.2%
Net income attributable to common  $689    8.4%  $48    1.3%  $641    1324.1%

 

Wholesale trading revenue, net: 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.

 

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. Market conditions during 2012 were characterized by milder than normal weather – with a warmer winter and cooler summer - and cheap and ample natural gas supplies, which suppresses prices. 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 we are buying or selling.

 

The average for the PJM West Peak price during the first quarter of 2013 was $41.08/MWh with a standard deviation of $8.97, resulting in a coefficient of variation of 22%, compared to $34.77/MWh, $4.22, and 12% for the three months ended March 31, 2012. As shown by the table below, price levels and volatility were generally higher in 2013 as compared to 2012.

 

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PJM West Hub Peak  Jan  Feb  Mar  Q1 Avg/Sum
Price ($/MWh)                    
2013                    
Average   40.38    38.96    43.83    41.08 
This year vs last year   9%   16%   30%   18%
Maximum   77.67    48.90    60.06    77.67 
Minimum   29.70    33.61    35.79    29.70 
Standard deviation   13.17    4.29    6.08    8.97 
Coefficient of variation (stdev ÷ avg)   33%   11%   14%   22%
                     
2012                    
Average   37.10    33.49    33.77    34.77 
Maximum   50.15    40.27    41.40    50.15 
Minimum   31.25    30.70    28.81    28.81 
Standard deviation   5.07    2.40    3.93    4.22 
Coefficient of variation (stdev ÷ avg)   14%   7%   12%   12%
                     
Percentage Changes                    
2013                    
Average   3.0%   7.4%   4.2%   1.4%
Maximum   72.0%   89.3%   92.7%   370.1%
Minimum   -48.8%   -31.9%   -16.8%   -80.3%
Standard deviation   24.6%   28.7%   24.8%   23.0%
                     
Number of days                    
Up 10% or more   10    10    9    29 
Between 10% up and 10% down   12    10    12    34 
Down 10% or more   9    8    10    27 
                     
2012                    
Average   4.7%   -5.9%   3.6%   0.8%
Maximum   65.9%   17.2%   117.7%   117.7%
Minimum   -27.6%   -51.4%   -19.3%   -51.4%
Standard deviation   23.8%   13.1%   27.3%   22.5%
                     
Number of days                    
Up 10% or more   10    5    10    25 
Between 10% up and 10% down   11    16    12    39 
Down 10% or less   10    8    9    27 

 

According to NOAA data, for the three months ended March 31, 2013, heating degree-days for the U.S. were 2,255 or 27% higher than 2012’s figure of 1,782 and 4% above the 30 year normal (1983-2012) of 2,167.

 

Cooling degree-days during the first quarter of 2013 totaled 32 compared to a normal of 35 and 67 for the same period last year, making the period slightly cooler than usual and about 52% cooler than the same period in 2012.

 

38
 

 

    Jan  Feb  Mar  Q1 Avg/Sum
U.S. Heating Degree-Days                       
This year  2013   840    744    671    2,255 
Last year  2012   769    633    380    1,782 
This year vs last year      71    111    291    473 
This year vs last year percent cha      9%   18%   77%   27%
                        
Normal (1983-2012)      878    714    575    2,167 
This year vs normal      (38)   30    96    88 
This year vs normal percent change      -4%   4%   17%   4%
                   
U.S. Cooling Degree-Days                       
This year  2013   14    9    9    32 
Last year  2012   11    11    45    67 
This year vs last year      3    (2)   (36)   (35)
This year vs last year percent change      27%   -18%   -80%   -52%
                        
Normal (1983-2012)      8    8    19    35 
This year vs normal      6    1    (10)   (3)
This year vs normal percent change      70%   9%   -52%   -9%
                        
U.S. Temperature                       
This year  2013   32.0°F   34.8°F   40.8°F    35.8°F
Last year  2012   36.5°F   38.3°F   51.2°F    42.0°F
This year vs last year      -4.5°F   -3.6°F   -10.5°F    -6.2°F
This year vs last year percent change      -12%   -9%   -20%   -15%
                        
Normal (1983-2012)      32.5°F   36.2°F   44.3°F    37.7°F
This year vs normal      -0.5°F   -1.4°F   -3.6°F    -1.8°F
This year vs normal percent change      -2%   -4%   -8%   -5%

 

EIA data indicates that for the three months ended March 31, 2013, the Henry Hub natural gas spot price averaged $3.49/MCF, 43% more 2012’s first quarter average mark of $2.44 and 35% below the 5 year average price of $5.34. Weekly storage levels averaged 2,422 BCF or 11% less in 2012 but were still 19% above the 5-year average.

 

     Jan  Feb  Mar  Q1 Avg/Sum
Henry Hub Natural Gas Spot Price ($/MCF)                       
This year average  2013   3.33    3.33    3.81    3.49 
Last year average  2012   2.67    2.50    2.17    2.44 
This year vs last year      25%   33%   75%   43%
                        
5 year average (2007-2012)      5.49    5.50    5.07    5.34 
This year vs 5 year average      -39%   -39%   -25%   -35%
                        
Working Gas in Underground Storage, Lower 48, EIA Weekly Estimates (BCF)                       
This year  2013   3,071    2,460    1,873    2,422 
Last year  2012   3,183    2,689    2,417    2,736 
This year vs last year      -4%   -9%   -23%   -11%
                        
5 year average (2007-2012)      2,731    2,033    1,721    2,043 
This year vs 5 year average      12%   21%   9%   19%

 

Largely as a result of these factors, for the three months ended March 31, 2013, net trading revenue increased by $2,984,000 or 78.3% to $6,797,000 compared to $3,813,000 for the first quarter of 2012.

 

39
 

 

 

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.

 

Our customer base consists largely of residential consumers with a few small commercial accounts. The following table summarizes our retail results to date. Note that there is a lag between the dates a customer signs up for, or drops, service with us and the date that such transaction takes effect.

 

As the following table shows, we recognized revenue of $1,437,000 in the first quarter of 2013. As TSE was not in business until July 1, 2012, there is no quarterly comparative for the first quarter. However, for the third and fourth quarters and the year ended December 31, 2012, our retail revenues totaled $134,000, $683,000, and $817,000, respectively.

 

Town Square Energy
Unit Sales, Revenues & Average Retail Price; Customer Counts; Load & Usage
    Q3    Q4    Year    Jan 31,    Feb 28,    Mar 31,    Q1 
    2012    2012    2012    2013    2013    2013    2013 
Unit Sales, Revenues & Average Price                                   
Revenues ($000s)   134    683    817    422    454    561    1,437 
Unit sales (MWh)   1,987    9,477    11,464    5,776    5,964    7,359    19,099 
Average retail price ($/kWh)   6.74    7.21    7.13    7.31    7.61    7.63    7.53 
                                    
Customer Counts                                   
New sign-ups during period   1,894    2,525    4,419    845    2,293    671    3,809 
Avg daily sign-up rate   10.3    27.4    24.1    27.3    81.9    21.6    42.3 
                                    
Receiving service, EoP   1,634    3,958    3,958    4,977    5,866    8,012    8,012 
Net periodic growth rate   na     142.2%   na     25.7%   17.9%   36.6%   102.4%
                                    
Load & Usage                                   
Total load (MW)   7.134    15.160    na     17.653    24.044    25.824    na  
Total daily use (MWh)   68.236    151.469    na     178.802    245.586    265.158    na  
                                    
Avg load/customer (kW)   4.366    3.830    na     3.547    4.099    3.223    na  
Avg daily use/customer (kWh)   42    38    na     36    42    33    na  

 

Costs of retail electricity sold: Our cost of electricity sold includes the costs of purchased power such as energy, capacity, and ancillary services, renewable energy certificates, bad debt expense, and gains net of losses and commissions on derivative contracts used to hedge power purchase costs. For the first quarter ended March 31, 2013, the Company purchased all of the electricity sold to retail customers in ISO-NE’s day-ahead and real-time wholesale markets. The Company is required to maintain a cash deposit in a separate account to meet ISO-NE’s financial assurance requirements to purchase energy, ancillary services, and capacity which amount is included in “trading accounts and deposits”.

 

For the first quarter of 2013, we hedged the cost of 15,925 MWh or 83% of the 19,099 MWh of electricity sold to our retail customers in such period. This hedge had the effect of decreasing cost of goods sold by $425,703. As of March 31, 2013, we had hedged the cost of 71,360 MWh (approximately 70% of expected electricity purchases for the balance of 2013) and $49,061, representing the net gain on the effective portion of the hedge, was deferred in accumulated other comprehensive income. This amount is expected to be reclassified to cost of energy sold by December 31, 2013.

 

40
 

 

Compensation and benefits: Compensation and related expenses 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 March 31, 2013, compensation and benefits increased by $1,501,000 or 71.4% to $3,601,000 compared to $2,101,000 for the same period in 2012. Our personnel expense is directly related to the revenue we record, since our trader’s compensation is tied to revenue production.

 

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 first quarter of 2013, professional fees increased by $302,000 to $927,000 compared to $625,000 in the first three months of 2012. The increase was due to the addition of a trading consultant at CTG. Certain professional fees related to the Notes Offering incurred prior to its effective date on May 10, 2012 were capitalized as deferred financing costs. The Company also continues to incur legal fees in connection with the Canadian former employee litigation.

 

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

 

For the three months ended March 31, 2013, these costs increased by approximately $288,000 to $632,000 compared to $344,000 for the same period in 2012. The increase was related to marketing costs and administrative expenses associated with the Notes Offering and certain costs and expenses related to our retail business such as contract fees, office expenses, and travel, neither of which were incurred in the first quarter of 2012. Depreciation and amortization is included in other general and administrative expenses and also increased in the first quarter of 2013 by $82,000 from $52,000 to $134,000.

 

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 quarter ended March 31, 2013, trading tools and subscriptions increased by $21,000 or 10.4% to $223,000 compared to $202,000 for the comparable period in 2012. Many of the contracts renew each year at an increased cost.

 

Other income (expense): Other expense, net of other income, decreased by $24,000 to $341,000 for 2013’s first quarter compared to $365,000 for 2012. As the principal component of other expense, interest expense decreased by $17,000 to $349,000 for the year from $365,000 during in 2012. The decrease was attributed primarily to a reduction of the weighted average interest rate paid on our debt, partially offset by an increase in outstanding debt from $6,280,000 at December 31, 2012 compared to $6,805,000 at March 31, 2013.

 

Provision for taxes: The tax provision is directly related to foreign income taxes associated with CAN. The decrease in taxes is attributed to a decrease in taxable income for CAN.

 

Preferred distributions: During the first quarter ended March 31, 2013, we paid $137,000 in preferred distributions compared to $92,000 in the first three months of 2012. The increase is solely related to the issuance date of the redeemable preferred on January 31, 2012.

 

41
 

 

Liquidity, Capital Resources, and Cash Flow

 

In our wholesale trading business, we require a significant amount of cash to maintain collateral with the trading markets in which we operate, which in turn allows us to trade in those markets and generate revenues. With respect to our retail operation, in addition to collateral posted with ISO-NE that allows us to acquire power for our customers, we are also required to fund accounts receivable. 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 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. If we fail to make loan payments when due, certain of our lenders have the option to declare any unpaid principal balances and all accrued interest thereon to be immediately due and payable. 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 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 is at the discretion of our Board of Governors 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 Governors, the Company would have insufficient cash to meet anticipated redemption or repayment obligations.

 

We believe we have sufficient cash on hand, coupled with anticipated cash generated from operating activities, the anticipated proceeds from the Notes Offering, and certain other financing activities as described below to meet our operating cash requirements for at least the next twelve months.

 

42
 

 

The following table is presented as a measure of our liquidity and capital resources as of the dates indicated:

 

   At      
Dollars in thousands  March 31, 2013  December 31, 2012  Increase (decrease)
  Dollars  Percent
of total
assets
  Dollars  Percent
of total
assets
  Dollars  Percent
Liquidity                              
Cash  $1,010    5.8%  $772    4.7%  $238    30.8%
Trading accounts and deposits   13,440    77.3%   12,025    73.9%   1,415    11.8%
Accounts receivable - trade   1,113    6.4%   2,191    13.5%   (1,078)   -49.2%
Total liquid assets   15,563    89.5%   14,988    92.2%   575    3.8%
Total assets  $17,382    100.0%  $16,263    100.0%   1,119    6.9%
                               
Capital Resources                              
Notes payable                              
Demand or current   4,949    28.5%   5,006    30.8%   (57)   -1.1%
Long term   1,857    10.7%   1,274    7.8%   583    45.8%
Total notes payable   6,806    39.2%   6,280    38.6%   526    8.4%
Redeemable preferred units   2,745    15.8%   2,745    16.9%       0.0%
Common   3,154    18.1%   3,654    22.5%   (500)   -13.7%
Total capitalization  $12,705    73.0%  $12,679    78.0%   26    0.2%

 

The table below summarizes our primary sources and uses of cash for the three months ended March 31, 2013 and 2012 as derived from the statements of cash flows:

 

    For The Three Months Ended March 31, 
Dollars in thousands             Increase (decrease) 
   2013    2012    Dollars    Percent 
Net cash provided by (used in):                
Operating activities  $1,260   $1,233   $27   2.20%
Investing activities   (90)   (56)   (34)   60.7%
Financing activities   (894)   (1,049)   155    -14.8%
Net cash flow   276    128    148    115.6%
                    
Effect of exchange rate changes on cash   (37)   (11)   26    236.4%
                     
Cash:                    
Beginning of period   772    971    (199)   -20.5%
End of period  $1,010   $1,088   $(77)   -7.2%

 

At March 31, 2013, our debt totaled $6,805,000 compared to $6,280,000 as of the prior year end. During the first quarter of 2013, we generated $1,260,000 from operating activities and used $28,000 for purchases of equipment and furniture and $63,000 on payments related to our noncompetition obligation. We used $894,000 for financing activities. Total debt increased by $420,000, net of issuances, and we paid $136,000 and $1,283,000 of preferred and common distributions, respectively.

 

During the quarter ended March 31, 2012, we generated $1,233,000 of cash from operations, made $56,000 of capital expenditures, and used $1,049,000 for financing activities.

 

43
 

 

Financing

 

Effective January 31, 2012, TCP sold certain financial rights, but not governance rights, to 496 new membership units, which we refer to as “preferred units”, to John O. Hanson for a purchase price of $2,745,000, paid by conversion of certain notes payable to him. Effective July 1, 2012, these preferred units were exchanged for preferred units with identical terms issued by TCPH. From the effective date to the redemption date, we shall pay Mr. Hanson or his designee a guaranteed payment or distribution of $45,750 per month. At any time prior to December 31, 2013, we may repurchase the units for $2,745,000. If we do not repurchase the units prior to such date, Mr. Hanson may require Timothy S. Krieger, our Chief Executive Officer, to repurchase them on such date. In addition, should we default on our obligations to Mr. Hanson, payment of all specified amounts has been personally guaranteed by Mr. Krieger.

 

In February 2012, we executed a $25,000,000 Futures Risk-Based Margin Finance Agreement (the “Margin Line” and the “Margin Agreement”, respectively) 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 Margin Agreement, the Company is 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. As of March 31, 2013, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants.

 

On February 20, 2012, the HTS Note was amended to accommodate the Margin Agreement as follows:

 

CEF may not draw more than $7,000,000 until the Note is paid in full;
CEF must maintain not less than $3,000,000 in its ABN AMRO account;
The Company shall retain as capital all funds drawn under the Margin Agreement until the HTS Note is paid in full;
The Company shall not distribute to its members, directly or indirectly, any of the proceeds of the Margin Agreement;
The Company shall maintain a separate accounting with respect to the withdrawal and use of funds; and
The maturity date of the HTS Note was shortened by one year to October 1, 2013 and, consequently, the Company is required to make a balloon principal payment of $1,943,004 at maturity.

 

On May 10, 2012, our Form S-1 registration statement relating to our offer and sale of Renewable Unsecured Subordinated Notes (File No. 333-179460) was declared effective by the SEC, and our offering of notes 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 first three months of 2013, we incurred $268,000 of offering-related expenses, including marketing and printing expense, additional legal and accounting fees, filing fees, and trustee fees. These costs and expenses are expensed as incurred.

 

Through May 12, 2013, we have sold a total of $1,189,012 in principal amount of Notes and redeemed $47,186, for a net raise to date of $1,141,826.

 

44
 

 

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 presentations of liquidity measures and debt-to-equity ratios. 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.

 

Critical Accounting Policies and Estimates

 

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 is recorded in the period in which customers consume the commodity, net of any applicable sales tax. 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.

 

Profits Interest Payments

 

Two of our second-tier subsidiaries (SUM and CEF) have Class B members. Under the terms of such 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 and profits interests payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the balance sheet.

 

For the three months ended March 31, 2013 and 2012, we recorded $1,474,405 and $842,202, respectively, in salaries and wages and related taxes, representing the allocation of profits to Class B members. The amount of accrued profits interests included in accrued compensation at March 31, 2013 and 2012 was $1,474,405 and $825,697, respectively.

 

 

45
 

Item 3 - Quantitative and Qualitative Disclosures about Market Risk

 

None

 

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 March 31, 2013, 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 March 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

46
 

 

Part II – Other Information

 

Item 1 - Legal Proceedings

 

See Note 11. Commitments and Contingencies on page 26 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

 

47
 

 

Item 6 - Exhibits

 

Exhibit Number   Description
10.1   Guaranty, dated April 16, 2013 by the Company in favor of PJM Settlement, Inc. (for Cygnus Energy Futures, LLC)
10.2   Guaranty, dated April 16, 2013 by the Company in favor of PJM Settlement, Inc. (for Summit Energy, LLC)
10.3   Guaranty, dated April 16, 2013 by the Company in favor of PJM Settlement, Inc. (for Twin Cities Power, LLC)
31.1   Certification of Chief Executive Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.1   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

_______________

*Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and are otherwise not subject to liability under those sections.

 

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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.

 

        TWIN CITIES POWER HOLDINGS, LLC
         
Dated: May 15, 2013   By:   /s/ Timothy S. Krieger
        Timothy S. Krieger
Chief Executive Officer, President and Chairman of the Board
(principal executive officer)
         
         
         
         
         
Dated: May 15, 2013   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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