10-K 1 twincities_10k-123113.htm ANNUAL REPORT

 

UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-K

 

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

 

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013

 

or

 

oTRANSITION 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)

 

Securities registered under Sections 12(b) or 12(g) of the Act   Name of each exchange on which registered
None   None

 

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act

$50,000,000

3 and 6 Month and 1, 2, 3, 4, 5 and 10 Year Renewable Unsecured Subordinated Notes

_________________________________________________________

 

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

 

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

 

Indicate by check mark 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 o Accelerated filer o Non-accelerated filer o Smaller reporting company x

 

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

 

 
 

 

TABLE OF CONTENTS

 

Part I 4
Item 1 - Business 4
Definitions 4
Company Overview 9
The Electric Power Industry 11
Wholesale Electricity Markets 12
Retail Electricity Markets 14
Seasonality 18
Wholesale Trading 18
Market Risk Management 19
Credit Risk Management 20
Competition 21
Retail Energy Services 21
Sales and Marketing 22
Energy Supply 22
Credit Risk Management 24
Competition 24
Real Estate Development 24
Intellectual Property 26
Personnel 27
Regulatory Matters 27
Item 1A – Risk Factors 28
Risks Related to Our Businesses 28
Wholesale Trading 28
Retail Energy Services 29
Real Estate Development 31
Risks Related to Our Company 32
Risks Related to the Notes 34
Item 1B – Unresolved Staff Comments 34
Item 2 – Properties 35
Item 3 – Legal Proceedings 36
Item 4 – Mine Safety Disclosures 37
Part II 38
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 38
Item 6 – Selected Consolidated Financial Data 38
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation 39
Forward Looking Statements 39
Overview 39
Results of Operations 40
Liquidity, Capital Resources, and Cash Flow 46
Financing 48
Non-GAAP Financial Measures 49
Critical Accounting Policies and Estimates 49

 

2
 

 

Item 7A – Quantitative and Qualitative Disclosures about Market Risk 50
Commodity Price Risk 50
Interest Rate Risk 51
Liquidity Risk 52
Wholesale Counterparty Credit Risk 52
Retail Customer Credit Risk 52
Foreign Exchange Risk 52
Item 8 – Financial Statements and Supplementary Data 53
Management’s Report on Internal Controls over Financial Reporting 53
Report of Independent Registered Public Accounting Firm 54
Consolidated Balance Sheets 55
Consolidated Statements of Comprehensive Income 56
Consolidated Statements of Cash Flows 57
Consolidated Statements of Changes in Members’ Equity 59
Notes to Consolidated Financial Statements 60
Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 83
Item 9A – Controls and Procedures 83
Item 9B – Other Information 83
Part III 84
Item 10 – Directors, Executive Officers, and Corporate Governance 84
Governors and Executive Officers 84
Board Composition, Election of Governors, and Committees 86
Risk Management Committee 86
Audit Committee 86
Compensation Committee 87
Item 11 – Executive Compensation 88
Summary Compensation Table 88
Outstanding Equity Awards 88
Governor Compensation 88
Retirement Plans 89
Potential Payments Upon Termination or Change-in-Control 89
Employment Agreements 89
Compensation Policies and Practices as They Relate to Risk Management 90
Indemnification of Governors and Executive Officers and Limitations of Liability 91
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 92
Item 13 – Certain Relationships, Related Transactions, and Director Independence 92
Joinder Agreement with Former Members 93
Real Estate Leases 93
Acquisition Advisory Agreement 93
Item 14 – Principal Accountants’ Fees and Services 93
Audit and Non-Audit Fees 94
Audit Committee Pre-Approval Policies 94
Part IV 95
Item 15 – Exhibits, Financial Statement Schedules 95
Signatures 100
Schedule 12.1 - Computation of Ratio of Earnings to Fixed Charges 101
Schedule 12.2 - Computation of Ratio of Earnings to Fixed Charges and Preferred Distributions 102
Exhibit 21 - List of Subsidiaries of Registrant 103

 

3
 

 

Part I

 

Item 1 - Business

 

Definitions

 

Abbreviation or acronym   Definition
ABN AMRO   ABN AMRO Clearing Chicago, LLC and ABN AMRO Clearing Bank, N.V.
AESO   Alberta Electric System Operator, a statutory corporation of the Province of Alberta, is an ISO serving the Alberta Interconnected Electric System
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. One “MMBtu” is one million Btu.
C$   Canadian dollars
CAISO   California Independent System Operator Corporation, an ISO serving 80% of California and a small part of Nevada
CEF   Cygnus Energy Futures, LLC, a wholly-owned subsidiary of CP and a second-tier subsidiary of the Company
CFTC   Commodity Futures Trading Commission, an independent agency of the United States government that regulates futures and option markets
CLP   Connecticut Light & Power Company, an EDC in Connecticut
CME   CME Group Inc. operates the CME (Chicago Mercantile Exchange), CBOT (Chicago Board of Trade), NYMEX (New York Mercantile Exchange), and COMEX (Commodities Exchange) derivatives exchanges and also offers certain cleared OTC products and services
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, an electricity retailer acquired by TCP on June 29, 2012
CSE   Comparison shopping engine, a web site that compares prices for specific products. While most comparison shopping engines do not offer the products or services themselves, some may earn commissions when users follow the links in the search results and make a purchase from an online vendor
CTG   Chesapeake Trading Group, LLC, a wholly-owned subsidiary of TCP and a second-tier subsidiary of the Company
DEG   Discount Energy Group, LLC, a wholly-owned subsidiary of REH and a second-tier subsidiary of the Company, effective January 2, 2014

 

4
 

 

Abbreviation or acronym   Definition
Degree-days; CDD; HDD  

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

 

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

DOE   U.S. Department of Energy
EDC   Electric distribution company
EIA   Energy Information Administration, an independent agency within DOE
ERCOT   Electric Reliability Council of Texas, an ISO managing 85% of the electric Load of Texas and subject to oversight by the Public Utility Commission of Texas and the Texas Legislature but not FERC
FASB   Financial Accounting Standards Board
FERC   Federal Energy Regulatory Commission, an independent regulatory agency within DOE
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 Parties   Collectively, Robert O. Schachter, an individual, HTS Capital, LLC, and Clearwaters Capital, LLC, both affiliates of Mr. Schachter
ICE   IntercontinentalExchange Group, Inc. operates a network of 17 regulated exchanges and 6 clearinghouses for financial and commodity markets in the U.S., Canada, Europe, and Asia. In November 2013, ICE completed the acquisition of NYSE Euronext.
ISO; RTO   Independent System Operator, a non-profit organization formed at the direction or recommendation of FERC that coordinates, controls, and monitors the operation of a bulk electric power system, usually within a single U.S. state, but sometimes encompassing multiple states. A Regional Transmission Organization (“RTO”) typically performs the same functions as an ISO, but covers a larger area. ISOs and RTOs may also operate centrally cleared wholesale markets for electric power quoted on both a “real-time” and “day ahead” basis.
ISO-NE   ISO New England Inc., an RTO serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont
MCA   The Company’s Member Control Agreement, as amended
MISO   Midcontinent Independent System Operator, Inc., (formerly the Midwest Independent Transmission System Operator, Inc.), an RTO serving all or part of Arkansas, Illinois, Indiana, Iowa, Louisiana, Manitoba, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, and Wisconsin

 

5
 

 

Abbreviation or acronym   Definition
MCF   One thousand cubic feet, a common unit of price measure for natural gas. In 2010, one MCF of natural gas had a heat content of 1,025 Btu.
NERC   North American Electric Reliability Corporation, a non-profit corporation formed on March 28, 2006 as the successor to the National Electric Reliability Council, also known as NERC, formed in 1968. NERC is the designated Electric Reliability Organization (“ERO”) for the U.S. and operates under the auspices of FERC.
NGX   Natural Gas Exchange Inc., headquartered in Calgary, Alberta provides electronic trading, central counterparty clearing, and data services to the North American natural gas and electricity markets. NGX is wholly owned by TMX Group Inc. which collectively manages all aspects of Canada’s senior and junior equity markets.
NOAA   National Oceanic and Atmospheric Administration, an agency of the U.S. Department of Commerce
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
NRSRO   A SEC-recognized Nationally Recognized Statistical Rating Organization; The major NRSROs that rate utilities are Standard & Poor’s Financial Services LLC (“S&P”), Moody’s Investor Services, Inc. (“Moody’s), and Fitch Ratings Inc. (“Fitch”)
NYISO   New York Independent System Operator, an ISO serving New York state
OTC   Over-the-counter
PJM   PJM Interconnection, a RTO serving all or part of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.
POR; non-POR   All states with restructured retail markets have implemented laws and regulations with respect to permitted billing, credit, and collections practices. Some of these states require an EDC billing customers in their service territory on behalf of suppliers operating there to purchase the receivables generated as a result of energy sales, generally at a modest discount to reflect bad debt experience. These states are known as “purchase of receivables” or “POR” jurisdictions while those without this provision are known as “non-POR” areas.
PURPA   Public Utilities Regulatory Policy Act of 1978
RECs   Renewable energy certificates represent the property rights to the environmental, social, and other non-power qualities of renewable electricity generation and can be sold separately from the underlying physical electricity.
REH   Retail Energy Holdings, LLC, a first-tier subsidiary of the Company
SEC   U.S. Securities and Exchange Commission, an independent agency of the United States government with primary responsibility for enforcing federal securities laws and regulating the securities industry and stock exchanges

 

6
 

 

Abbreviation or acronym   Definition
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
TCPC   Twin Cities Power – Canada, Ltd., an inactive wholly-owned subsidiary of TCE and a second-tier subsidiary of the Company
TCPH   Twin Cities Power Holdings, LLC
TSE   Town Square Energy, initially, an accounting division of TCP resulting from the acquisition of the business and assets of CP&U. Effective June 1, 2013, TSE became a wholly-owned first-tier subsidiary of the Company and on October 25, 2013, it became a wholly owned subsidiary of REH and a second-tier subsidiary of TCPH
UI   The United Illuminating Company, an EDC in Connecticut
VaR   Value-at-Risk is a measure of the risk of loss on a specific portfolio of financial assets. For a given portfolio, probability, and time horizon, VaR is the value at which the probability that a mark-to-market loss over the given time horizon exceeds the calculated value, assuming normal markets and no trading. For example, if a portfolio has a one-day, 5% VaR of $1 million, there is a 5% probability that the portfolio will fall in value by more than $1 million over a one-day period.

 

7
 

 

 

Abbreviation or acronym   Definition

Watt (W);

Watt-hour (Wh)

 

Although in everyday usage, the terms “energy” and “power” are essentially synonyms, scientists, engineers, and the energy business distinguish between them. Technically, energy is the ability to do work, or move a mass a particular distance by the application of force while power is the rate at which energy is generated or consumed.

 

In the case of electricity, power is measured in watts (W) and is equal to voltage or the difference in charge between two points multiplied by amperage or the current or rate of electrical flow. The energy supplied or consumed by a circuit is measured in watt-hours (Wh). For example, when a light bulb with a power rating of 100W is turned on for one hour, the energy used is 100 watt-hours. This same amount of energy would light a 40-watt bulb for 2.5 hours or a 50-watt bulb for 2.0 hours.

 

Multiples of watts and watt-hours are measured using International Systems of Units (“SI”) conventions. For example: 

 

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

 

 

   

Kilowatt (kW) or kilowatt-hour (kWh): one thousand watts or watt-hours. Kilowatt-hours are typically used to measure residential energy consumption and retail prices. One kWh is equal to 3,412 Btu, but fuel with a heat content of 7,000 to 11,500 Btu must be consumed to generate and deliver one kWh of electricity.

 

Megawatt (MW) or megawatt-hour (MWh): one million watts or watt-hours or one thousand kilowatts or kilowatt-hours. Megawatts are typically used to measure electrical generation capacity and megawatt-hours are the pricing units used in the wholesale electricity market.

 

 

8
 

 

Company Overview

 

Through its wholly-owned subsidiaries, TCPH trades financial and physical electricity contracts in North American wholesale markets regulated by FERC and operated by ISOs and RTOs, trades energy derivative contracts on exchanges regulated by the CFTC, including ICE, NGX, and CME, provides electricity supply services to retail customers in certain states that permit retail choice, and is engaged in certain real estate development activities. Consequently, the Company has three major business segments used to measure its activity – wholesale trading, retail energy services, and real estate development.

 

Organizational Structure

 

Our organizational structure (active entities only) as of January 2, 2014 is outlined below.

 

 

 

Key

Orange - Holding Company · Green – Wholesale Trading · Blue – Retail Energy Services · Gray – Real Estate Development

 

History

 

TCPH was formed as a Minnesota limited liability company on December 30, 2009. Effective December 31, 2011, the members of TCP, CP, and TCE each contributed all of their ownership interests in these entities to TCPH in exchange for ownership interests in TCPH (the “Reorganization”). The result of this Reorganization was our current holding company structure, with TCPH becoming the sole member of each of TCP, CP, and TCE. Today, TCPH owns 100% of the outstanding equity interests of TCP, CP, REH, and Cyclone.

 

The Company has its roots in a dairy products trading company, Fairway Dairy & Ingredients, LLC (“Fairway”). As a division of Fairway, doing business originally as Twin Cities Power Generation, and then as Twin Cities Power, it was granted market-based rate authorization - the authority to buy and sell electricity in wholesale markets - by FERC in January 2004. As of January 1, 2007, TCP was spun out of Fairway and commenced its existence as an independent company.

 

TCP conducts operations directly and through wholly-owned subsidiaries. CTG, a Minnesota limited liability company, was formed on June 19, 2009. SUM, a Minnesota limited liability company, was formed on December 4, 2009 and a SUM employee currently has a profits interest in the entity.

 

9
 

 

CP was formed on March 14, 2008. CP conducts business through its wholly-owned operating subsidiary, CEF, a Minnesota limited liability company formed on July 24, 2007. Two CEF employees each currently have a profits interest in CEF.

 

TCE, inactive today, was formerly known as Alberta Power, LLC, and was formed on March 27, 2008. Canadian operations were conducted through TCE’s wholly-owned subsidiary, TCPC, which was formed on January 29, 2008 as a Canadian unlimited liability corporation. On February 1, 2011, a major restructuring of TCPC began. In February 2012, TCPC was converted to a regular Alberta corporation and during the third quarter of 2012, after review of the progress of the restructuring, management concluded that it was unlikely that TCPC would ever be able to provide an adequate return. Consequently, on September 5, 2012, TCE resolved that TCPC should cease operations by September 14, 2012.

 

On June 29, 2012, TCP acquired certain assets and the business of CP&U, a retail energy business operating in Connecticut. The business was renamed “Town Square Energy” and on July 1, 2012, it began operating as an accounting division of TCP, selling electricity to residential and small commercial customers in Connecticut at variable and fixed rates.

 

Effective June 1, 2013, TSE was reorganized as a wholly-owned subsidiary of TCPH. On October 25, 2013, in anticipation of the receipt of FERC approval of the Company’s acquisition of Discount Energy Group, LLC (“DEG”), a retail energy business licensed by Maryland, New Jersey, Pennsylvania, and Ohio, the Company formed a new first-tier subsidiary, Retail Energy Holdings, LLC (“REH”), and transferred the ownership of TSE to this entity. FERC approval of the acquisition of DEG was received on December 13, 2013 and the transaction closed on January 2, 2014.

 

On October 23, 2013, we formed Cyclone Partners, LLC (“Cyclone”) as a wholly-owned subsidiary of the Company to take advantage of certain investment opportunities present in the residential real estate market, particularly in the southern portion of the Minneapolis-St. Paul metropolitan area.

 

The Company is headquartered at 16233 Kenyon Ave, Suite 210, Lakeville, MN 55044, telephone (952) 241-3103. In addition to our headquarters, we operate from five other locations. See “Properties”.

 

10
 

 

The Electric Power Industry

 

By virtually any measure, the electric power industry in the U.S. is substantial. According to EIA data, in 2012, the industry generated and sold 3,695 GWh (down 1.5% from 2011) for more than $363.6 billion (down 2.0%) to over 145 million customers (up 0.5%).

 

U.S. Electric Power Industry Revenue, Unit Sales, Customers, and Average Retail Price 2012 & 2011

 

           

Avg

Retail

    
   Revenues  Unit Sales  Customers  Price  Growth Rates, 2012 vs 2011 
   $millions  Pct  GWh  Pct  000s  Pct  (¢/kWh)  Revs  Sales  Custs  ARP 
2012                                             
Residential   163,280   44.9%  1,375   37.2%  126,832   87.3%  11.88   -2.1%  -3.4%  0.5%  1.4%
Commercial   133,898   36.8%  1,327   35.9%  17,729   12.2%  10.09   -1.5%  -0.1%  0.5%  -1.4%
Industrial & other   66,509  18.3%  993   26.9%  732   0.5%  6.70   -2.8%  -0.6%  0.6%  -2.2%
                                              
Total industry   363,687   100.0%  3,695   100.0%  145,294   100.0%  9.84   -2.0%  -1.5%  0.5%  -0.5%
                                              
Residential   152,817   42.0%  1,298   35.1%  118,650   81.7%  11.77   -3.8%  -5.2%  -1.4%  1.5%
Commercial   106,012   29.1%  1,073   29.1%  16,112   11.1%  9.88   -2.1%  -1.6%  -1.3%  -0.6%
Industrial & other   52,799   14.5%  809   21.9%  681   0.5%  6.52   -3.0%  -1.8%  -0.3%  -1.2%
                                              
Full service providers   311,628   85.7%  3,180   86.1%  135,443   93.2%  9.80   -3.1%  -3.1%  -1.4%  0.0%
                                              
Residential   10,464   2.9%  77   2.1%  8,182   5.6%  13.64   32.0%  41.1%  40.2%  -6.5%
Commercial   27,886   7.7%  254   6.9%  1,617   1.1%  10.99   1.0%  6.7%  22.8%  -5.4%
Industrial & other   13,709   3.8%  184   5.0%  51   0.0%  7.46   -1.8% 5.1%  14.0%  -6.6%
                                              
Restructured retail   52,059   14.3%  514   13.9%  9,851   6.8%  10.12   5.2%  10.1%  36.8%  -4.5%
                                              
Residential   5,776   1.6%              7.53   26.2%        -10.6%
Commercial   17,397   4.8%              6.86   -3.8%        -9.9%
Industrial & other   10,327   2.8%              5.62   -4.9%        -9.5%
                                              
Energy only providers   33,500   9.2%              6.51   -0.1%        -9.3%
                                              
Residential   4,687   1.3%              6.11   40.0%        -0.8%
Commercial   10,489   2.9%              4.13   10.1%        3.2%
Industrial & other   3,382   0.9%              1.84   8.9%        3.5%
                                              
Delivery service only   18,559   5.1%              3.61   16.2%        5.5%

______________

Source: U.S. EIA, released December 12, 2013, next release November 2014.

 

Physically, the nation’s power system includes generation resources, transmission lines, and retail distribution systems. At year-end 2012, the industry’s bulk power system consisted of over 19,000 generating units with total nameplate capacity of 1,168 GW and over 190,000 circuit-miles of high-voltage (over 100kV) transmission lines. The retail distribution system includes substations, wires, poles, metering, billing, and related support systems. According to the IRS, as of the end of 2010, total assets of the utility industry exceeded $1.5 trillion.

 

Today, the industry includes any entity producing, selling, or distributing electricity. As of the end of 2012, according to the EIA, participants numbered over 2,100 and included investor-owned, publicly-owned, cooperative, and federal utilities and about 110 non-utility power producers. Power marketers and retail energy providers do not own any generation but buy and sell in wholesale and retail markets. Finally, participants in wholesale power markets include banks, hedge funds, private equity firms, and trading houses.

 

Electric power in commercial quantities, unlike other energy commodities such as coal or natural gas, cannot be stored, i.e., 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 have obvious implications for electricity market regulations and structures.

 

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

 

11
 

 

Since PURPA, the nation has moved from a system of vertically integrated monopolies providing retail service at state-determined, cost-based rates to one where the ownership of generation assets is no longer regulated and the majority of the nation’s bulk power systems (generation and transmission) are operated under the supervision of the Federal Energy Regulatory Commission, an independent agency within the U.S. Department of Energy. Today, prices at the wholesale level are determined by market forces, subject to a federal regulatory framework focused on ensuring fair competition and reliability of supply. Furthermore, while some states have restructured their markets such that individual consumers are allowed to choose their electricity supplier, most state public utility commissions continue to regulate their utilities under the traditional cost-based framework.

 

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

 

Wholesale electricity 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.

 

Factors that affect electricity prices in the long term include climate, fuel prices and availability, generation and efficiency technologies deployed, population growth, economic activity, and governmental policies and regulatory actions with respect to energy and the environment.

 

Wholesale Electricity Markets

 

After PURPA, the Energy Policy Act of 1992 was the next major legislative step towards full deregulation of wholesale power markets and in 1996, FERC issued Orders 888 and 889, which led to the creation of the network of “OASIS” or Open Access Same-Time Information System nodes, which allowed for energy to be scheduled across multiple power systems.

 

In December 1999, FERC issued Order 2000 calling for electric utilities to form RTOs or ISOs to operate the nation’s bulk power system with the intended benefits of 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.

 

12
 

 
FERC’s U.S. Wholesale Electricity Markets

 

 

FERC’s U.S. Wholesale Electricity Markets
Market Name ISO Approximate Generating Capacity Key Hubs or Zones
no 299,712 MW Entergy, Southern, TVA
yes 167,454 MW AEP GEN, AEP-Dayton, Chicago GEN, Chicago, Dominion, Eastern, Northern Illinois, New Jersey, Ohio, West INT, Western
yes 137,232 MW Cinergy, First Energy, IL, MI, MN
yes 71,244 MW Houston, North, South, West
no 57,120 MW California-Oregon Border (COB), Mid-Columbia (Mid-C)
yes 56,347 MW NP-15, ZP-15, SP-15

(Southwest Power Pool)

yes 50,600 MW SPP provides transmission service on facilities owned by its members and operates a real-time energy imbalance service (EIS) market. Market participants trade physical electricity bilaterally, either directly, through brokers, or through the EIS market
no 45,459 MW Four Corners, Mead, Palo Verde
yes 39,704 MW West (Zone A), Genesee (B), Central (C), North (D), Mohawk Valley (E), Capital (F), Hudson Valley (G), Millwood (H), Dunwoodie (I), New York City (J), Long Island (K)
yes 36,820 MW CT, ME, NH, RI, VT, NEMA, SEMA,WCMA, Mass Hub
Source: Company analysis of FERC Market Oversight web pages.

 

In addition to controlling the physical flow of power within its area of responsibility, many ISOs also operate wholesale markets for real-time and day-ahead electricity, as well as ancillary services required to ensure system reliability. To date, seven ISOs have been formed in the U.S. In the parts of the country where ISOs have not been established, active wholesale markets are still present, although they operate with different structures.

 

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Trading activity in ISO markets is often characterized by the acquisition of electricity at a given location such as a node or hub and its delivery to another. “Virtual” or purely 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 electricity itself, but in either case, the ISO serves as the counter-party and central clearinghouse for all trades.

 

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

 

Retail Electricity Markets

 

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

 

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

 

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

 

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

 

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

 

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Today, 15 years after Massachusetts and Rhode Island became the first states to effectively implement choice in 1998, 20 jurisdictions have some form of choice. However, it is important to note that not all consumers in choice jurisdictions are able to select their electricity supplier as they are served by public or cooperative utilities. Nonetheless, in the 14 areas where all rate classes have choice there are almost 24 million residential and over 2.8 million non-residential customers using about 353,000,000 MWh annually. Overall, we believe that choice is proving to be a boon for consumers. According to an analysis of data from the EIA, between 2000 and 2012 retail rates for all customer sectors in states with restructured retail markets increased by only 12.0% compared with a 34.9% increase in states that rely on regulated utilities.

 

 

 

 

Retail Electric Bills: Unbundling of consumer electric bills in restructured markets made many aware for the first time exactly what they were paying for. In general, the bills of retail electricity customers include numerous costs and charges that can be classified into three major categories – generation costs, delivery charges, and governmental policy costs:

·Energy Costs: In addition to energy, this category may include other wholesale supply costs such as capacity charges and ancillary services.
·Delivery Charges: Depending upon the state, transmission charges may be included in energy costs. Distribution costs recover the EDCs’ costs to own, operate, and maintain their distribution systems.
·Governmental Policy Costs: These charges include the costs of federal and state polices with respect to electricity and may include:

 

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oTransition charges are costs associated with moving from a regulated market to a restructured one and allow EDCs to recapture stranded costs that would otherwise be unrecoverable after deregulation.
oSocietal benefits charges include the costs of government-mandated programs such as universal service, lifeline service, and energy efficiency programs.
oSales and use taxes include taxes collected by state and local authorities on retail electricity sales.

 

According to analysis of EIA data, on average between 2000 and 2012 (the latest year for which information is available) energy and delivery costs accounted for about 67% and 33%, respectively, of the average retail electricity price. Of course, these percentages fluctuate from year to year and state to state, primarily due to wholesale energy market conditions, weather, and state rules. The following graph, prepared from EIA data, shows the composition of electric bills in Connecticut from 2000 to 2012 and illustrates these points.

 


 

Billing Systems: In general, there are three billing structures available to competitive suppliers in restructured markets:

 

·Under a “utility consolidated billing” system, also known as “UCB”, the utility is responsible for billing all retail customers for all electric service charges as well as the collection of outstanding accounts. Retailer charges included in the utility’s bill are calculated in one of two ways:

oFor “rate ready” utilities, the retailer posts its rates with the utility and the utility calculates the charges for inclusion on the customer’s bill.
oFor “bill ready” utilities, retailers receive usage data from the utility and calculate the amount owed by the customer. This amount is then communicated back to the utility for inclusion on the customer’s bill.

·Under the “dual billing” framework, the utility sends bills to the customer for transmission and distribution charges and retailers send separate bills for generation charges. Each is responsible for the collection of its outstanding accounts and has direct credit exposure to the customer.
·Under the “retailer consolidated billing” structure, retailers are responsible for billing customers for all charges and, consequently, have direct credit exposure to the customer and are responsible for collection of all outstanding amounts.

 

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Purchase of Receivables: Some states require that utilities billing customers in their service territory on behalf of a retailer purchase the receivables generated as a result of energy sales. These states are known as “purchase of receivables” or “POR” jurisdictions. The purchase generally occurs at a modest discount of 0% to 2.5% to reflect bad debt experience by customer class within the service territory. Retailers have no customer credit exposure other than the bad debt charge because the utility pays regardless of whether or not the customer does. However, if a customer fails to pay, the utility will typically disconnect service, which results in the loss of the account for the retailer.

 

POR Programs in Jurisdictions with Full Retail Choice
Type Count States
Full or recourse 7 Connecticut, Illinois, Maryland, New Jersey, New York, Ohio (Duke only), Pennsylvania
In progress 1 District of Columbia, Massachusetts, Ohio (non-Duke)
None 6 Delaware, Maine, New Hampshire, Rhode Island, Texas
Total 14 --

 

In states with retail choice but without POR programs - the “non-POR” jurisdictions - retailers are exposed to the credit risk of the customer. New Jersey is currently the only “recourse POR” state. Under these rules, retailers have no exposure to customer credit risk provided that the customer is billed under a utility’s consolidated billing program. However, if an electric account is in default for 60 days (about 90 days from invoice date), the utility has the option to convert the customer to dual billing. In Ohio, the only POR service territory is currently that served by Duke Energy Ohio in the southern portion of the state around Cincinnati. The rest of the state is non-POR. The District of Columbia and Massachusetts are in the process of becoming POR jurisdictions.

 

POR laws have the effect of converting the retailer’s exposure to its customers’ credit to that of the applicable utility, which is generally “investment grade” under the scales of the Nationally Recognized Statistical Rating Organizations recognized by the SEC. The major NRSROs that rate utilities are Standard & Poor’s Financial Services LLC (“S&P”), Moody’s Investor Services, Inc. (“Moody’s), and Fitch Ratings Inc. (“Fitch”). “BBB-” by S&P or Fitch or “Baa3” by Moody’s are considered to be the lowest investment grades by market participants.

 

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The table below summarizes the credit ratings of certain investor-owned utilities operating in selected retail choice jurisdictions:

 

S&P's Long Term Credit Ratings of Investor Owned Utilities with 25,000 or More Retail Customers Operating in 14 Full Choice Jurisdictions, July 2013

 

Jurisdiction  POR Status  Number of
IOUs
   Number of
Rated IOUs
   Average
Credit Rating
   Number of
Non-Rated IOUs
 
Connecticut  POR   2    2     BBB+     
Delaware  non-POR   1    1     BBB+     
District of Columbia  POR in process   1    1     BBB+     
Illinois  POR   4    3     BBB    1 
Maine  non-POR   1    1     A-     
Maryland  POR   4    4     BBB     
Massachusetts  POR in process   5    4     BBB+    1 
New Hampshire  non-POR   3    2     A-    1 
New Jersey  recourse POR   4    4     BBB+     
New York  POR   8    7     BBB+    1 
Ohio (Duke)  POR   1    1     BBB+     
Ohio (non-Duke)  POR in process   5    5     BBB-     
Pennsylvania  POR   11    7     BBB-    4 
Rhode Island  non-POR   2    1     A-    1 
Texas  non-POR   6    5     BBB+    1 
                        
     Total/average      58    48     BBB+    10 


Seasonality

 

Annual and quarterly operating results of the Company can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas and interruptions in fuel supply infrastructure can increase seasonal fuel and power price volatility, with summer and winter being the most volatile seasons. The sale of electric power to retail customers is also a seasonal business. As a result, net working capital requirements for the Company's retail operations generally increase during peak months and then decline during off-peak months. Weather may impact operating results and extreme weather conditions could materially affect results of operations. The rates charged to retail customers may be impacted by fluctuations in total power prices and market dynamics like the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.

 

Wholesale Trading

 

The Company trades financial and physical contracts in wholesale electricity markets managed by ISOs or RTOs (collectively, the “ISOs”) including those managed by MISO, ERCOT, PJM, ISO-NE, and NYISO. We also hold market based rate authority under the rules and regulations of FERC. The Company also trades electricity and other energy-related commodities and derivatives on exchanges operated by ICE, NGX, and CME. U.S. ISOs are regulated by the FERC, a division of the DOE. The CFTC regulates ICE, NGX and CME.

 

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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. On ICE, NGX, and CME, the Company trades electricity, natural gas, and oil derivatives and may hold an open interest in these contracts overnight or longer. On very rare occasions, the Company may also trade physical electricity between certain markets, buying in one and selling in another.

 

Market Risk Management

 

We believe that the physical infrastructure of the North American electrical grid provides arbitrage trading opportunities, and we expect these opportunities will remain in place for the long term. We have created a proprietary software system, DataLiveä, that allows us to summarize thousands of data points into decision support tools. We believe this system assists our energy traders in achieving more profitable trading through faster and better informed decisions, increased trading volume, and reduced risk.

 

Our wholesale trading business model incorporates the following key elements:

·Minimize market risk by trading principally instruments with terms of one week or less;
·Minimize credit risk by trading primarily in regulated markets with a centralized counterparty, which may also be described as “cleared” markets;
·Maximize return on capital deployed through position and value at risk (“VaR”) limits; and
·Employ primarily experienced traders.

 

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Although we believe the trading strategies we employ provide protection from excessive losses due to the focus on very near-term markets, wholesale electricity markets can be volatile. Our market risk management policy establishes certain risk measurements and trading limits. The Board has established a Risk Management Committee, which has responsibility for overseeing the risk function and setting risk limits. Each of our operating subsidiaries has separate risk limits. If at any time the accumulation of all entities’ positions are more than the “global limit” set, our risk managers have the authority to take market positions opposite to those of our traders to hedge our risk. To date, we have not had such a situation. No assurance can be given, however, that our risk management procedures will actually enable us to prevent losses.

 

Position Limits: Our energy traders are required to stay within intra-day position limits as established based on daily and intra-day volatility for the market in question.

 

Stop Loss: Each position has a stop loss limit set by management. When a loss at this level is attained, the entire position must be closed out as soon as possible, ideally within one trading hour.

 

Value-at-Risk: Each trading unit has a VaR limit. Our daily VaR model is based upon log-normal returns calculated from the last 30 business days of prices at the 95% confidence level, or 1.645 standard deviations, with a one day liquidity assumption. VaR is calculated daily, using positions and prices updated to the close of business on the previous day. The price history used is ideally that of the instrument held; however, in the cases where those prices are unavailable, benchmarking is used. Our VaR calculations always use the market value of the position, not its cost. In the case of a position where it is likely to take more than one day to close out, VaR will be multiplied by the square root of the average days to liquidate the position in a stressed market.

 

Stress Testing: Stress testing is intended to capture extreme, but plausible, market conditions in order to anticipate potential losses. Each trading group has a stress test limit established. Stress testing uses a single scenario consisting of projected values for applicable risk factors at the end of the horizon. Based on these values, the portfolio is marked-to-market at these stressed prices. We use the largest 5 day percent change in the last 4 years for each position and apply it to the current market price. Our positions are then marked-to-market based on these stressed prices.

 

See also “Quantitative and Qualitative Disclosures about Market Risk”.

 

Credit Risk Management

 

Like other wholesale market participants, we are typically required to place cash collateral with market operators in order to trade, with the specific amounts depending upon the rules and requirements of the particular market. Accordingly, we have cash deposits in collateral accounts at the various ISOs with which we trade and with our clearing brokers. All of these accounts are uninsured.

 

Most ISOs have a mechanism known as ‘‘uplift,’’ whereby any credit losses are allocated to all market members based on their level of participation. This minimizes the possibility of a market operator experiencing credit losses, as they otherwise operate as profit-neutral entities. Historically, we have not had a participation level of greater than 1.0% in any ISO market. Exposure to credit losses of the clearing agents is fully collateralized by the positions of their members and they do not uplift any credit losses.

 

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Our wholesale trading credit policy calls for annual reviews of each investment-grade credit risk and quarterly reviews for those rated below investment grade. All counterparties may also be reviewed on an irregular basis if new information is received. Our credit review includes, but is not limited to, a review of financial statements, rating agency reports, and other pertinent indicators of credit strength. If a guaranty is being utilized by a counter-party to establish credit with us, the guarantor will be evaluated and credit will be granted based on the financial strength of the guarantor. In addition, we perform follow-up reviews based on the below schedule.

 

  Review frequency Internal credit scoring required
Rated Entities      
Investment grade  Annually  No
Sub-investment grade  Quarterly  Yes
       
Non-Rated Entities      
Investment grade equivalent  Annually  Yes
Sub-investment grade equivalent  Quarterly  Yes
       
ISOs and RTOs  Annually  No

 

As of March 3, 2014, the ISOs and RTOs with which we may do business are rated as follows: CAISO - “A+” by Fitch; ERCOT - “Aa3” by Moody’s; ISO-NE - not rated; MISO - “A+” by S&P; NYISO - not rated; PJM - “Aa3” by Moody’s; and SPP - “A” by Fitch.

 

From time to time to supply our retail customers, we may purchase energy on a bilateral basis from wholesale suppliers other than an ISO. In these instances, we are exposed to the risk that such supplier may fail to deliver to the ISO for our account, possibly for a credit related reason. If this were to occur, we would then be forced to buy the required power from either the ISO or another supplier. Consequently, we monitor the credit of each of these suppliers in accordance with our wholesale trading policies as outlined above.

 

Competition

 

Given the nature of the wholesale trading business, we do not compete with other entities for market share. Instead, we compete with other entities to attract and retain the most qualified energy traders, who are the primary source of our revenue. In our industry, the ability to employ and retain experienced, successful energy traders is paramount to having a successful and profitable business operation. We believe our compensation structure and flexible policy regarding working from regional locations near the traders’ preferred residences enable us to attract and retain highly qualified traders. In addition, we believe DataLive enhances our traders’ success.

 

Retail Energy Services

 

On June 29, 2012, we entered into the retail energy services business via the acquisition of certain assets and the business of Community Power & Utility LLC, a small retail energy business licensed by Connecticut. The business was renamed Town Square Energy (“TSE”) and on July 1, 2012, we began selling electricity to residential and small commercial customers. On April 12, April 16, and October 9, 2013, we received approval of our competitive supplier licenses from the states of Massachusetts, Rhode Island, and New Hampshire, respectively, although we have not yet launched our services in these states.

 

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Effective June 1, 2013, TSE was reorganized as a wholly-owned subsidiary of TCPH. On October 25, 2013, in anticipation of the receipt of FERC approval of the Company’s acquisition of Discount Energy Group, LLC (“DEG”), a retail energy business licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio, the Company formed a new first-tier subsidiary, REH, and transferred the ownership of TSE to this entity. FERC approval of the acquisition of DEG was received on December 13, 2013 and the transaction closed on January 2, 2014.

 

Consequently, the retail markets in which the Company expects to compete in 2014 include at least the following states: Connecticut, Maryland, Massachusetts, New Jersey, Pennsylvania, and Ohio.

 

Sales and Marketing

 

Our services are made available to customers under fixed price and variable rate contracts as well as some that provide up to 100% renewable energy. All contracts regardless of price and term are subject to standard terms and conditions as filed from time to time with state regulatory authorities. Retail customers make purchase decisions based on a variety of factors, including price, customer service, brand, product choices, bundles, or value-added features.

 

The prices we offer customers are determined by us and are not subject to regulation. The terms we offer are also determined by us, and we develop such to align with regulatory requirements within each state where we do business. However, due to unprecedented cold weather during the winter of 2013-14 that caused prices to spike to record high levels, we expect additional rules and regulations to be imposed on the pricing and terms offered by competitive energy suppliers in the near future.

 

The electricity we sell is generally metered and delivered to our customers by local utilities. As such, we do not have a maintenance or service staff for customer locations. These utilities also provide billing and collection services for the majority of our customers on our behalf, generally under the utility consolidated billing structure.

 

Our principal marketing strategy throughout 2013 was to offer comparatively low prices to consumers through our website, townsquareenergy.com. Most of our customers come to our site after visiting ctenergyinfo.com, a comparison shopping engine offered by the state of Connecticut to its residents. We generally price our contracts such that our offers provide savings compared to the standard offer default rates offered by the incumbent utilities and, consequently, appear in the first two or three listings below their offerings on ctenergyinfo.com. We expect to employ other direct marketing methods such as radio, direct mail, and outbound telemarketing as we expand our operations.

 

Energy Supply

 

We do not own any electrical power generation, transmission, or distribution facilities and utilize ISOs and utilities for transmission and distribution services. We buy the energy we need to serve our customers in wholesale markets under both short- and long-term contracts for delivery to the various utility load zones we serve. We generally purchase most of the power demanded by our customers in the day-ahead markets operated by the ISOs and have also entered into certain bilateral contracts with wholesale energy market participants. The ISOs also perform real-time load balancing which ensures that the amount of electricity purchased is equal to the amount necessary to service customer demand at any point in time. We are charged or credited for balancing electricity purchased and sold for our account by the ISOs.

 

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We are also required to meet certain minimum green energy supply criteria in some of the states in which we operate and we meet these thresholds by acquiring renewable energy certificates or “RECs”. In addition, we offer green energy products to our customers in several territories and we buy additional voluntary RECs to satisfy the requirements for these customers. RECs represent the property rights to the environmental, social, and other non-power qualities of renewable electricity generation and can be sold separately from the underlying physical electricity. As renewable generators produce electricity, they create one REC for every megawatt-hour of electricity. If the physical electricity and the associated RECs are sold to separate buyers, the electricity is no longer considered “renewable” or “green” as the REC is what conveys the attributes and benefits of the renewable electricity, not the electricity itself.

 

We manage our exposure to movements in wholesale energy prices by hedging. The derivatives we use are principally physical forward and financial futures contracts whereby we agree with a counterparty to take physical delivery or cash settle the difference between the floating price and the fixed price on a notional quantity of electricity for a specified time frame. In addition, we may buy put and call options as hedges against unfavorable fluctuations in market prices. However, deviations between forecasted and actual customer usage, or “volumetric risk”, impacts us by reducing or increasing revenues and gross margins from expected results and may also impact our hedging program by causing an under- or over-hedged situation since we remain subject to commodity risk for any differences between the actual quantities used by our customers and the forecasted quantities upon which our hedging is based.

 

Our hedging strategy is based on, among other variables, forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms within a given period. This variability is exaggerated as a result of our concentration in the residential customer segment, in which energy usage is highly sensitive to weather conditions which impact heating and cooling demand. Cooling degree-days and heating degree-days are widely used in the energy industry for measuring the impact of weather patterns on energy usage. CDD represents the number of degrees that a day’s average temperature is above 65° Fahrenheit and people start to use air conditioning while HDD are the number of degrees that a day’s average temperature is below 65° Fahrenheit and people start to use heating.

 

Our retail hedging policy is summarized as follows:

 

1.At least 75% of forecasted fixed price retail load in high price volatility months (June, July, and August and December, January, and February) will be hedged.

 

2.At least 50% of forecasted variable price retail load will be hedged in the month prior to the delivery month.

 

3.When possible, hedges will be executed at the zonal or nodal location of the load. If derivatives indexed to such zonal or nodal location are not available or liquid, the hedge will be executed at the nearest highly correlated (r-squared greater than 0.80) liquid hub.

 

4.Additional hedges may be executed incrementally as the retail load served grows.

 

5.Appropriate hedge designation memoranda that qualify derivative contracts for hedge accounting treatment under GAAP shall be prepared except for intra-month and prompt month purchases.

 

6.Among others as may be approved from time to time by the Risk Management Committee, derivatives approved for use as hedging instruments include exchange-traded futures and swaps and over-the-counter options.

 

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Credit Risk Management

 

In connection with the retail electricity business, retailers like the Company provide trade credit to both utilities and retail customers by providing generation service. As part of implementing retail choice, all states with restructured retail energy markets have put in place laws and regulations with respect to permitted billing, credit, and collections practices. This exposes us to certain credit risks which we manage in different ways.

 

We believe the credit policy and underwriting strategy presented below allows us to prudently accept any business in non-POR areas by taking deposits only from the riskiest accounts. Collection activity and cost is largely eliminated since if a customer fails to pay in a timely fashion, then we will simply cease providing service and apply the deposit to the outstanding bill. Our retail credit underwriting policy is summarized as follows:

 

1.If a prospect is located in a POR area, we will accept the account as the utility is the account obligor.

 

2.If a prospect is located in a non-POR area and is a residential account, we will check their three-bureau FICO score:
a.If the score is above a certain threshold, we will accept the account without a deposit.
b.If the score is below the threshold, we will accept the account with a deposit equal to 90 days of expected energy sales.

 

3.If a prospect is located in a non-POR area and is a non-residential account, we will check their trade credit score:
a.If the score is above the threshold level, we will accept the account without a deposit.
b.If the score is below the threshold, we will accept the account with a deposit equal to 90 days of expected energy sales.

 

4.To size any deposits required, we will estimate or check the account’s last 12 months of historical energy usage and the most recent average forecast wholesale energy price for the area for the next 12 months. Our general deposit sizing formula is as follows: Deposit = annual kWh usage x avg energy price/kWh ÷ 100 x deposit factor of 25%.

 

5.After a year of prompt payments on their account, the customer may elect to either have their deposit returned to them or applied to their account.

 

Competition

 

We compete with local utility companies in the areas where we provide service. Some utilities have affiliated companies that are retail energy suppliers, and many compete in the same markets as we do. We also compete with large energy companies as well as many independent suppliers. Many of these competitors or potential competitors may be larger and better capitalized than we are. This competition exposes us to the risk of losing customers, especially since our customers generally do not sign long term contracts.

 

Real Estate Development

 

On October 23, 2013, the Company formed Cyclone Partners, LLC (“Cyclone”) as a wholly-owned subsidiary to take advantage of certain perceived investment opportunities present in the residential real estate market, particularly in the southern portion of the Minneapolis-St. Paul metropolitan area. Specifically, Cyclone intends to acquire and develop land for resale, either as improved sites for construction of single- and multi-family homes or as completed dwellings. For the year ended December 31, 2013, Cyclone had no revenues and incurred $17,000 in allocated expenses, and at the same date, assets and equity totaled $784,169.

 

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According to the Minneapolis Area Association of Realtors® 2013 Annual Report on the Twin Cities Housing Market:

 

“It was a banner year for residential real estate across America. Nearly every metropolitan housing market embarked upon or continued along the road to recovery. Local and regional markets once burdened by excessive supply levels and heavy foreclosure loads have given way to multiple-offer situations, homes selling in record-low market times and prices rallying to multi-year highs in many cases.

 

The year 2013 brought tectonic shifts to housing's landscape. Many local markets transitioned from buyers' markets to sellers' markets. Closed sales are up. Days on market until sale are trending downward. The percent of list price received at sale is trending higher. Sellers even managed to post a notable gain.

 

Low (but upwardly mobile) mortgage rates, still affordable prices and a better jobs scene created a triple play that helped bolster consumer confidence and galvanize local markets. Rising prices have the dual benefit of further cementing confidence as well as lifting homeowners out of underwater positions, which should create more inventories in 2014.”

 

The following table describes 2013’s residential real estate market conditions in the Twin Cities region as well as selected areas of interest.

 

Area Overview   2013
Total Closed Sales
    Change
from
2012
    New
Construc-tion
Pct
    Town-house/ Condo
Pct
    Distressed
Pct
    Cum-ulative
Days on
Market
    Pct of
Original
Price
Received
 
                                   
Twin Cities Region   53,087    8.8%   6.9%   22.6%   26.4%   83    96.1%
                                 
  Scott County   2,461    11.9%   9.4%   24.0%   26.7%   81    96.6%
    Credit River Twshp   42    16.7%   11.9%   0.0%   21.4%   119    97.7%
                                 
  Dakota County   6,336    4.9%   7.6%   32.1%   27.4%   74    96.7%
    Lakeville   1,106    19.7%   15.5%   20.1%   24.2%   76    97.1%

 

Median Prices   2009    2010    2011    2012    2013    Change
from
2012
    Change
from
2009
 
                                   
Twin Cities Region   165,000    169,900    150,000    167,900    192,000    14.4%   16.4%
                                    
  Scott County   200,000    190,000    180,000    197,001    226,550    15.0%   13.3%
    Credit River Twshp   402,250    400,000    392,000    438,000    449,000    2.5%   11.6%
                                    
  Dakota County   174,250    175,000    156,000    170,359    200,000    17.4%   14.8%
    Lakeville   224,188    225,000    205,000    226,000    258,000    14.2%   15.1%

______________

Source

Minneapolis Area Association of Realtors®

 

Bitterbush Pass: On November 15, 2013, Cyclone bought a 1.10 acre lot legally described as Lot 2, Block 1, Territory 1st Addition, for a little more than $109,000. The address of the lot is 21580 Bitterbush Pass, Credit River Township, Minnesota. The upscale Territory development of single family homes is located approximately two miles west of I-35 north of Lucerne Boulevard (County Road 70 exit) and all construction on the property is subject to the rules of the Territory Homeowners Association. Although Cyclone’s final plan for the property is yet to be decided upon, it is anticipated that about $10,000 in additional capital will be invested in the Bitterbush Pass project in 2014.

 

25
 

 

Fox Meadows: On December 18, 2013, Cyclone bought a defaulted note secured by a first mortgage on the Fox Meadows property as described below from Bremer Bank, National Association. The purchase price was $353,504 and included $340,000 of principal and $13,504 of accrued interest. Cyclone intends to foreclose on the note and thereby obtain title to the land. Once title to the property has been obtained, the note will be cancelled and the land received will be reclassified to “land held for development”. Once title has been obtained, expected to be on or about April 20, 2014, Cyclone expects to proceed with the development of the property.

 

The 1.73 acre Fox Meadows site is located at 18665 Joplin Avenue south of 185th Street West in Lakeville, Minnesota, approximately one mile east of I-35, and represents an expansion of an established owner-occupied townhome development. On July 23, 2013, the property was appraised on an “as is” basis at $370,000 and on an “as complete” basis at $600,000, assuming completion of the current plat of up to 40 attached residential building sites.

 

In addition to the purchase price of the mortgage note, the Company has pledged cash collateral to the City of Lakeville in the amount of $320,188 to secure the future development of the property, bringing its total investment in the Fox Meadows project to $673,692 as of December 31, 2013.

 

Although the final plan for the property is yet to be decided upon, it is anticipated that about $550,000 in additional capital will be invested in the Fox Meadows project in 2014.

 

Intellectual Property

 

We have developed a proprietary software system, DataLive, which allows us to summarize thousands of data points into decision support tools for our energy traders. We believe this system results in more profitable trading through faster and better informed decisions, increased trading volume, and reduced risk. On April 3, 2013, we received Certificate of Copyright Registration number TX7-717-805 from the U.S. Copyright Office. We have also applied to the U.S. Patent and Trademark Office for a trademark on the DataLive name and expect that such will be granted in 2014. We have also developed a proprietary risk management database known as the “SQL Database”, which delivers price data to our risk managers.

 

We employ two full time software engineers who develop software tools for our traders. In 2013 and 2012, we spent approximately $270,000 and $165,000, respectively, on research and development of DataLive.

 

In 2013, we capitalized $60,265 of development costs of internal-use software for use in our retail business as equipment, to be amortized on a straight-line basis over 36 months.

 

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Personnel

 

As of March 15, 2014, we employed 38 persons, including 20 electricity traders, 1 risk manager, and 17 executives and administrative personnel. We have 35 full-time and 3 part-time employees. We do not employ any unionized labor. We have entered into employment agreements with all of our traders and administrative employees. We also have 7 independent consultants under contract.

 

To attract and retain qualified personnel, particularly traders, we employ a competitive compensation system that incorporates dedicated capital and a payout of approximately 35-40% of net revenues. We also have a policy of not requiring traders to relocate. Instead, we have invested in centralized trading platforms and strong risk management disciplines. Consequently, traders can live where they want. Traders are, however, responsible for covering their expenses before sharing in the profits of their trading activities. This strategy also provides them with a sense of being responsible for the success of their own individual trading activities. While we can make no assurances, we believe these policies will help us to retain the successful energy traders who are so vital to our operations and success.

 

Other employee benefits available through, or paid by, us include medical and dental insurance, a 401(k) plan, employee-managed time off, and holiday pay.

 

Regulatory Matters

 

We are required to comply with the rules and regulations of FERC, the U.S. Department of Energy with regard to the export of electricity to Canada, the CFTC with respect to energy futures contracts, the Federal Trade Commission, the market rules and tariffs of the ISOs and RTOs of which we are a member. In addition to regulating our operations, FERC regulations also require us to make certain filings and applications for FERC approval prior to certain changes in our governance and ownership.

 

In addition to applicable Federal laws and regulations, we are also subject to the laws and regulations of the states in which we conduct business.

 

On July 16, 2013 the Public Utilities Regulatory Authority of Connecticut (“PURA”) opened Docket 13-07-18 entitled PURA Establishment of Rules for Electric Suppliers and EDCs Concerning Operations and Marketing in the Electric Retail Market (the “Docket”) According to the Docket: “Due to recent legislative changes and due to the spike in customer complaints against various electric suppliers in recent months, a proceeding is necessary for PURA to review the current operations and marketing rules governing participants in the Connecticut electric retail market. In this proceeding, PURA will clarify the new legislative requirements and establish rules and guidelines for electric suppliers and electric distribution companies concerning, but not limited to: customer switching practices, types of generation services or products allowed (fixed, variable rates, etc.), PURA filing requirements, the Rate Board, supplier marketing conduct, customer notices, and disclosure requirements”.

 

In December 2013, interrogatories were issued under the Docket to all licensed competitive suppliers in Connecticut and TSE has responded. Hearings are scheduled to begin in late March 2014, with PURA indicating a draft decision by the end June 2014.

 

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Item 1A – Risk Factors

 

If any of the following risks actually occur, our business, financial condition, and results of operations would suffer. The risks described below are not the only ones we face. Additional risks that we currently do not know about or that we currently believe to be immaterial may also impair our business, financial conditions, and results of operations.

 

Risks Related to Our Businesses

 

Wholesale Trading

 

We are largely dependent on our energy traders to generate our revenues.

 

We are largely dependent on the success of our energy traders to generate our revenues. While we have employment agreements with our traders, not all of them have non-competition provisions. Accordingly, a trader may leave us at any time. Further, 60% of our revenue in 2012 was generated by our top 5 most successful traders, and in 2013 our top 5 traders generated 77% of our revenue. The loss of any of these traders would have an immediate and potentially material adverse effect on our results of operations and if we are unable to hire replacements with comparable abilities, our results of operations, financial condition, and cash flows would suffer.

 

Our revenues and profitability could be adversely affected if a counterparty were to default in whole or in part on its obligations to us

 

We maintain cash balances in brokerage accounts that facilitate our trading activities. In addition, we have cash deposits in collateral accounts at various ISOs. All of these accounts are uninsured. When we place cash deposits in these accounts, we incur credit risk. Our revenues and profitability could be adversely affected if our brokers or counterparties were to default in whole or in part on their obligations to us. See “Business –Credit Risk Management”.

 

Our results of operations may be impaired as a result of a rogue trader.

 

A determined individual could operate as a “rogue trader” and act outside our delegations, controls, or code of conduct in pursuit of personal objectives that could be to the detriment of us, our members, and our creditors. In so doing, one of our traders could attempt to hide or create false transactions for personal gain. Such activities could adversely impact our results of operations, financial condition, and cash flows, and cause lawsuits, and regulatory intervention, the impact of which could materially, and adversely, affect our results of operations, financial condition, and cash flows.

 

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If we are unable to successfully compete for the best energy traders, our results of operations may be impaired.

 

Given the nature of our business, we do not compete with other entities for market share. Instead, we compete with other entities to attract and retain the most qualified energy traders, who are the primary source of our revenue. Our competitors may have greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures, more effective risk management policies and procedures and greater ability than us to withstand losses. Our competitors may also be able to respond more quickly to new laws or regulations or emerging technologies than we can. Our energy traders may leave us at any time to join a competitor or compete directly on their own, which would have an adverse effect on our results of operations and cash flow.

 

We may not be able to compete successfully against current and future competitors for the most qualified energy traders, and any failure to do so could have a material adverse effect on our business, financial condition, results of operations, and cash flow.

 

We may be unable to effectively protect our intellectual property, which may allow competitors to duplicate our technology and may adversely affect our ability to compete.

 

In order to attract and retain the most qualified energy traders, we need to offer them access to technology resources that enable them to trade as successfully as possible. In particular, we have developed a proprietary technology known as DataLive. To the extent that we are not able to protect our intellectual property effectively through patents, copyrights, contractual commitments with developers and employees, or other means, employees with knowledge of our intellectual property may leave and seek to exploit our intellectual property for their own or other’s advantage.

 

Retail Energy Services

 

Volatility in prices and consumption patterns could have an adverse effect on our revenues, costs, and results of operations.

 

Unexpected volatility in prices and constraints in the availability of fuel supplies, particularly natural gas, may have an adverse impact on the cost of the electricity that we sell to our customers. Furthermore, consumption of energy is significantly affected by weather conditions. Typically, colder-than-normal winters and hotter-than-normal summers create higher demand and consumption for natural gas and electricity, respectively, and conversely, milder than normal weather may reduce the demand for energy. Natural gas prices also affect the cost of electricity as it is the fuel of choice for marginal generation requirements. As a result of these factors, we may be unable to correctly forecast the precise amount of energy our customers require and therefore put appropriate hedges in place. Furthermore, although we are able to hedge certain of the market risks we face; others cannot be hedged. Finally, we may not always choose to pass along increases in costs in order to maintain overall customer satisfaction and this action would have an adverse impact on our margins and results of operations. Alternatively, volatility in pricing related to the cost of energy may lead to increased customer attrition. Changes in these factors, as well as others, could have an adverse effect on our revenues, profitability, and growth or threaten the viability of our current business model.

 

29
 

 

We face risks that are beyond our control due to our reliance on third parties and on the electrical power and transmission infrastructure within the U.S.

 

Our ability to provide energy to our customers depends on the successful and reliable operations and facilities of third parties such as wholesale generators, the ISOs, and local distribution companies. The loss of use or destruction of third party facilities used to generate or transmit electricity due to extreme weather conditions, breakdowns, war, acts of terrorism, or other occurrences could greatly reduce our potential earnings and cash flows.

 

The retail energy business is highly competitive.

 

We compete on the basis of price, provision of services, and customer service. Increasing our market share depends in part on our ability to persuade customers to switch to our services. Our retail energy businesses face substantial competition both from incumbent utilities as well as from other retail providers, including affiliates of utilities in specific territories. Utilities and other more established competitors have certain advantages such as name recognition, financial strength, and long-standing relationships with customers. Persuading potential customers to switch to a new supplier of such important services is challenging. As a result, we may be forced to reduce prices or incur increased costs to gain market share, and we may not always be able pass along increases in commodity costs to customers. Existing or future competitors may have greater financial, technical, or other resources which could put us at a disadvantage. If we are not successful in convincing customers to switch, our business, results of operations and financial condition will be adversely affected.

 

Our growth depends on our ability to enter new markets.

 

We evaluate new markets for our business based on many factors, including the regulatory environment and our ability to procure energy to serve customers in a cost-efficient manner. We may expend substantial effort to obtain required licenses and connections with local distribution companies. Furthermore, there are regulatory differences between the markets that we currently operate in and new markets, including, but not limited to, exposure to credit risk, additional churn caused by tariff requirements, rate-setting requirements, and incremental billing costs. We may also incur significant customer acquisition costs and while we seek to purchase wholesale energy in transparent markets that reflect fair prices, there can be no assurance that we will be successful.

 

A track record of profitability for our retail energy business is not yet firmly established and we continue to face all the risks involved in entering into a new line of business, including the risk that we will not be able to recognize expected synergies with our wholesale trading operations. To date, we have relied heavily on acquiring existing businesses. Such acquisitions take significant time and effort to integrate into our existing operations and may distract management from the Company's current activities.

 

Unfair business practices or other activities of our competitors may adversely affect us.

 

Competitors in the retail market may engage in unfair business practices to sign up new customers, which may create an unfavorable impression about the industry on consumers or with regulators. Such unfair practices by other companies can adversely affect our ability to grow or maintain our customer base. The successes, failures, or other activities of our competitors within the markets that we serve may impact how we are perceived in the market.

 

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Our operating strategy is based on current regulatory conditions and assumptions, which could change or prove to be incorrect.

 

Since the passage of PURPA in 1978, regulation of the energy markets has been in flux at both the federal and state levels. In particular, any changes adopted by FERC, or changes in state or federal laws or regulations (including greenhouse gas laws) may affect the prices at which we purchase energy for our customers. While we endeavor to pass along increases in energy costs to our customers pursuant to our variable rate customer offerings, we may not always be able to do so due to competitive market forces and the risk of losing our customer base. In addition, regulatory changes may impact our ability to use different sales and marketing channels. Changes in these factors, as well as others, could have an adverse effect on our revenues, profitability, and growth or threaten the viability of our current business model.

 

Changes in certain programs in which we participate could disrupt our operations and adversely affect our results.

 

Certain programs required by state regulators have been implemented by utilities in most of the service territories in which we operate, one of which is purchase of receivables or POR. See “Business – Credit Risk Management – Retail Energy Services”. These programs are important to our control of bad debt risk. In the event that POR programs were to be revised or eliminated by state regulators or individual utilities, we would need to adjust our current strategy regarding customer acquisition and our focus on the growth of our customer base. We would also need to adjust our current business plan to reduce our exposure to existing customers who may pose a bad debt risk. Any failure to properly respond to changing conditions could adversely affect our results of operations and profitability.

 

Our retail businesses depend on maintaining licenses in the states in which we operate and any loss of such would adversely affect our business, prospects and financial condition.

 

We require licenses from public utility commissions and other regulatory organizations to operate our business. These agencies impose various requirements to obtain or maintain licenses. Further, certain non-governmental organizations have been focusing on the retail energy industry and the treatment of customers by certain of our competitors. Any negative publicity regarding the industry in general and us in particular could negatively affect our relationship with various commissions and regulatory agencies and could negatively impact our ability to obtain new licenses to expand operations or maintain the licenses currently held. Any loss of our licenses would cause a negative impact on our results of operations, financial condition and cash flow.

 

Real Estate Development

 

We may be unable to run our real estate development business profitably.

 

Our entry into the real estate development business will experience all the risks involved in entering into a new line of business, including the risk that we are unable to run the business profitably. We do not have experience managing a real estate development business.

 

31
 

 

Risks Related to Our Company

 

Our results of operations may be impaired by incorrect market price forecasts due to human or computer errors, weather events, natural disasters, malicious parties, market inequities, terrorism, illiquidity, or other market factors which impact the final published settlement price.

 

Our contracts are purchased at prices determined by the market. Our traders buy in anticipation of being able to sell at a higher price. That sales price may be unexpectedly impacted by a number of factors beyond our control, resulting in a sale price lower than the purchase price we paid. Our contracts settle to quoted market prices published by the ISOs and exchanges on which we trade. Internally prepared and externally obtained price forecasts that we rely on to execute trades may be incorrect due to human or computer errors, weather events, natural disasters, malicious parties, market inequities, terrorism, illiquidity or other market factors which impact the final published settlement price. Incorrect price forecasts could result in trading losses, which could materially and adversely affect our results of operations, financial condition, and cash flows.

 

We are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and results of operations.

 

We are subject to the jurisdiction of, and required to comply with the rules and regulations FERC, including the Federal Power Act, the U.S. Department of Energy with regard to the export of electricity to Canada, the CFTC with respect to energy derivative contracts, the Federal Trade Commission, the market rules and tariffs of the ISOs of which we are a member, and the laws, and actions of the judiciary, of the states and provinces in which we conduct business (collectively, the “Regulators”).

 

Our businesses are subject to changes in state and federal laws, and actions of the judiciary, and changing governmental policy and regulatory actions, and also the rules, guidelines and protocols of the wholesale and retail energy markets in which we participate. Changes in, revisions to, or reinterpretations of existing laws and regulations, for example, with respect to prices at which we may sell electricity, or competition in its generation and sale, may have an adverse effect on our businesses.

 

At any time these rules and regulations could change in a manner that impairs our ability to operate and subsequently impairs our results of operations, financial condition, and cash flows. Furthermore, at any time Regulators may also affect a market resettlement, which could retroactively change the quoted market prices or fees assessed, which could have a substantial impact on our results of operations, financial condition, and cash flows.

 

We need substantial liquidity to operate our business.

 

We need substantial liquidity to operate our businesses. For example, our wholesale trading revenues are limited to some extent by the amount of cash collateral we have posted with a market operator or exchange.

 

Our retail businesses also involve entering into contracts to purchase large quantities of electricity on an hourly basis. In general, the ISOs with which we do business require payment for the energy we purchase on a weekly or twice-weekly basis. In some markets, we are also required to buy capacity and certain ancillary services on a monthly basis, and in all cases, we are required to provide such markets with financial assurance, typically in the form of cash in an amount equal to 60 to 75 days’ worth of such purchases. However, we only receive payment from our customers on a monthly basis. Consequently, we require a substantial amount of liquidity and capital to both satisfy our payables and carry our receivables. While we have entered into an agreement with a wholesale electricity supplier to purchase power from them from time to time upon terms more favorable than that of the ISOs and are seeking additional agreements of a similar nature with others, such agreements may not fulfill all our requirements, and there can be no assurance that we will be successful in finding additional trade financing of such type.

 

Our access to bank credit is limited due to the nature of our operations. Historically, we funded our operations through borrowings from related and unrelated parties and internally generated cash flows. Beginning in May 2012, we began a direct public offering of our Renewable Unsecured Subordinated Notes and to March 27th, 2014, we have raised over $12,623,000. However, we may not be able to obtain sufficient funding for our future operations from such source to provide us with necessary liquidity. Difficulty in obtaining adequate credit and liquidity on commercially reasonable terms may adversely affect our business, prospects, and financial condition.

 

32
 

 

Our business depends on the continuing efforts of our management team and personnel and our efforts may be severely disrupted if we lose their services.

 

Our success depends on key members of our management team, the loss of whom could disrupt our business operation. Our business also requires a capable, well-trained workforce to operate effectively. There can be no assurance that we will be able to retain our qualified personnel, the loss of which may adversely affect our business, prospects, and financial condition.

 

We could be harmed by network disruptions, security breaches, or other significant disruptions, or failures of our IT infrastructure and related systems.

 

We face the risk, as does any company, of a breach of the security of, and unauthorized access to, our information systems, whether through cyber-attack, malware, computer viruses, or sabotage. Furthermore, the secure maintenance and transmission of information between us and our third party service providers is a critical element of our operations. If our information security were to be breached, our information and that of our customers may be lost, disclosed, accessed, or taken without our consent. Although we make significant efforts to maintain the security and integrity of our information systems, there can be no assurance that our efforts and measures will be effective or that attempted breaches or disruptions would not be successful or damaging, especially in light of the growing sophistication of cyber-attacks and intrusions. We may be unable to anticipate all potential types of attacks or intrusions or to implement adequate security barriers or other preventative measures.

 

Network disruptions, security breaches, and other significant failures of the information systems upon which we depend could: (a) disrupt the proper functioning of our operations; (b) result in unauthorized access to, and destruction, loss, theft, misappropriation, or release of our proprietary, confidential, sensitive, or otherwise valuable information, including trade secrets, which others could use to compete against us or for disruptive, destructive, or otherwise harmful purposes and outcomes; (c) require significant management attention and financial resources to remedy the resulting damage or change to our systems; (d) result in a loss of business or damage to our reputation; or (e) expose us to litigation, any or all of which could have a negative impact on our results of operations, financial condition, and cash flows.

 

One of our inactive subsidiaries is currently subject to an investigation by FERC that could result in liability.

 

In October 2011, FERC initiated a non-public formal investigation into power scheduling and trading by TCE in MISO. FERC is investigating scheduling and trading for the period from January 1, 2010 through May 31, 2011. In addition to the expense of legal fees, depending on the investigation outcome, we may be liable for potential disgorgement of profits and possible civil penalties. Since this investigation is on-going, we are 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. However, FERC has the authority to assess fines and penalties of up to $1.0 million per day and, if it is determined that serious offenses have been committed and fines and penalties are imposed, such could have a material adverse effect on us. See “Legal Proceedings”.

 

33
 

 

Shortcomings or failures in our systems, risk management methodology, internal control processes, or people could lead to disruption of our business, financial loss, or regulatory intervention.

 

We rely on our internal control systems and risk management methodologies to protect our operations from, among other things, improper activities by individuals within our organization. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, or regulatory intervention.

 

If we lose key personnel, our results of operations may be impaired.

 

We are dependent on the services of our senior management because of their experience and knowledge of the industry and our business. The loss of one or more of these key employees could seriously harm our business. It may be difficult to find a replacement with the same or similar level of experience or expertise. Competition for these types of personnel is high, and we may not be able to attract and retain qualified personnel on acceptable terms. Failure to recruit and retain such personnel could adversely affect our business, financial condition, results of operations and planned growth.

 

Risks Related to the Notes

 

The characteristics of our Notes, including the offered maturities and interest rates, and lack of collateral security, guarantee, financial covenants, or liquidity, may not satisfy your investment objectives.

 

Our Notes may not be suitable for every individual, and we advise all parties considering an investment to consult their investment, tax, and other professional financial advisors prior to purchasing Notes. The characteristics of the Notes, including their maturities, interest rates, and lack of liquidity, collateral security, guarantee, and financial covenants may not satisfy your investment objectives. The Notes may not be a suitable investment based on the ability to withstand a loss of interest or principal or other aspects of an individual’s financial situation, including income, net worth, financial needs, risk profile, return objectives, experience, and other factors. Prior to purchasing any Notes, one should consider their investment allocation with respect to the amount of the contemplated investment in the Notes in relation to their other investment holdings and the diversity of those holdings. While we require that you complete a subscription agreement that asks certain questions regarding suitability, we disclaim any responsibility for determining that the Notes are a suitable investment for anyone. Please refer to our prospectus for additional risk factors related to the Notes.

 

Item 1B – Unresolved Staff Comments

 

None.

 

34
 

 

Item 2 – Properties

 

We are headquartered at 16233 Kenyon Ave, Suite 210, Lakeville, MN 55044, telephone (952) 241-3103. In addition to our headquarters, we operate and currently lease office space in four other locations. We do not engage in any production or manufacturing activities, and we do not have any environmental issues related to our wholesale trading, retail energy services, or real estate development operations.

 

The following table summarizes key terms of the various leases for office space:

 

Location  Expiration
Date
   Square
Footage
    Monthly
Rent
    Personnel
at Location
 
                   
Lakeville, Minnesota*  12/31/2017   11,910   $12,264    17 
Gilbert, Arizona  1/31/2015   1,055    2,563    4 
Tulsa, Oklahoma*  2/28/2016   1,800    3,750    8 
East Windsor, New Jersey  9/30/2016   1,150    2,339    5 
Newtown, Pennsylvania  12/31/2017   1,711    2,250    4 
     Total    17,626   $23,166    38 

 

The Company is also obligated to pay $400 per month under a verbal month-to-month lease for certain office space in Wellesley, Massachusetts, which began in November 2011.

 

The lessor of our headquarters in Lakeville, Minnesota, Kenyon Holdings, LLC (“Kenyon”), is a related party. On January 1, 2013, the Company and Kenyon entered into a five year lease expiring December 31, 2017 at what it believes to be market rates. See “Certain Relationships and Related Transactions, and Director Independence - Real Estate Lease”.

 

The lessor of our office space in Tulsa, Oklahoma, the Brandon J. and Heather N. Day Revocable Trust (the “Day Trust”), is a related party. On March 5, 2013, CEF and the Day Trust entered into a lease expiring on February 28, 2016 at what the Company believes to be market rates. See “Certain Relationships and Related Transactions, and Director Independence - Real Estate Lease”.

 

35
 

 

Item 3 – Legal Proceedings

 

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, TCE may be liable for potential disgorgement of profits and 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.

 

Former Employee Litigation

 

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

 

In 2013, the former employees brought applications to amend their pleadings to include certain of TCPC’s U.S. affiliates (“Twin Cities USA”). One of the former employees abandoned their application and the applications of the other two were heard on April 29 and 30, 2013. In a decision dated January 31, 2014, the Court of Queen’s Bench dismissed these applications.

 

Separately, also on January 31, 2014, the Court of Queen’s Bench ordered Twin Cities USA to post security for costs in the sum of C$75,000 together with security for judgment in the sum of C$1,376,726. On February 25, 2014, Twin Cities USA posted the security for costs with the court and filed an appeal in the Court of Appeal of Alberta seeking a stay to set aside the obligation to post security for the judgment. On March 19, 2014, the request for a stay was denied.

 

Twin Cities USA and TCPC intend to continue to vigorously defend against the allegations and claims of the former employees and file counterclaims or amended counterclaims for losses suffered and costs incurred in responding to the FERC investigation, inappropriate expenses, and related matters. Given the failure of its appeal for a stay, in order to preserve its claims and counterclaims, Twin Cities USA posted the security for the judgment on March 28, 2014.

 

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 paid in full in July 2012.

 

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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 was briefed before the Court of Appeals and oral argument was held on April 16, 2013.

 

In an order issued August 6, 2013, the U.S. Court of Appeals remanded to FERC for further consideration the issue of recoupment of refunds that had previously been directed by FERC.  The Court found that FERC’s orders failed to explain why refund recoupment was warranted and therefore its recoupment directive was found to be arbitrary and capricious.  In response to this remand directive, on November 22, 2013 the financial marketer appellants and interveners, including TCPH entities, filed a motion before FERC requesting that it act quickly to reconsider the refund recoupment directive found arbitrary by the Court.

 

On February 20, 2014, the FERC issued an order establishing a briefing schedule allowing parties to the proceeding to provide briefs on whether or not the recoupment orders should be reconsidered.  Although briefing on all issues relevant to the remand was invited by FERC, it also presented five specific questions, primarily relating to the effect of the recoupment orders, for the parties to address.  Initial briefs are due within 45 days of this order and reply briefs are due 30 days after the initial briefs.

 

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

 

During the period from July 2009 to July 2011, due to our participation in PJM, we were required to pay certain balancing operating reserve charges. During the same period, DC Energy, LLC and DC Energy Mid-Atlantic, LLC (collectively, “DC Energy”) inappropriately avoided such payments by reporting certain transactions as internal bilateral transactions. A FERC order dated July 12, 2013 on Docket No. EL12-8-001 denied rehearing on a complaint  by DC Energy with respect to PJM’s plan to retroactively bill them for these charges. PJM’s settlement reruns associated with these adjustments began in July 2013 and are expected to take approximately six to eight months to complete. Through February 28, 2014, the Company has received refunds totaling $611,093 from PJM ($494,771 in 2013 and $116,322 in 2014) that have been recognized as revenue. DC Energy has filed an appeal with the U.S. Court of Appeals, and should it be successful in such action, the Company may be required to return some or all of the funds received with respect to the matter, however, no reserve for such has been recorded as the Company believes the possibility of such to be remote.

 

Item 4 – Mine Safety Disclosures

 

Not applicable.

 

 

37
 

 

Part II

 

Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Not applicable.

 

Item 6 – Selected Consolidated Financial Data

 

The following table sets forth selected consolidated financial data for the last two years derived from the audited consolidated financial statements of Twin Cities Power Holdings, LLC. The following information is only a summary and you should read it in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” beginning on page 39 and our consolidated financial statements and notes thereto found in “Financial Statements and Supplementary Data” beginning on page 53.

 

   Years ended December 31 
Dollars in thousands unless otherwise indicated  2013   2013 
Statements of Operations Data          
Net revenue  $32,785   $19,074 
Total operating expenses   29,176    16,036 
Operating income   3,610    3,038 
Net other income (expense)   (1,469)   (1,051)
Income before income taxes   2,140    1,987 
Provision for taxes   9    56 
Net income   2,131    1,931 
Preferred distributions   (549)   (503)
Net income attributable to common  $1,582   $1,427 
Ratio of earnings to fixed charges (1)   2.26x   2.61x
           
Balance Sheet Data          
Cash and trading deposits  $13,675   $12,797 
Total assets   17,562    16,263 
Total debt   10,185    6,280 
Total liabilities   12,813    9,864 
Total redeemable preferred & members' equity   4,748    6,399 

______________

(1)Fixed charges include interest expense, one-third of operating lease rental expense as reported in the footnotes to our financial statements, and amortization of deferred financing costs. We have included one-third of the operating lease rental expense because that is the portion the Company estimates to be the interest component attributable to such rent expense, with the remaining two-thirds considered to be depreciation.

 

38
 

 

Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation

 

Forward Looking Statements

 

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-K, 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 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.

 

These statements are qualified in their entirety by reference to, and are accompanied by, the factors detailed in “Risk Factors” of this Form 10-K, in addition to 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.

 

Overview

 

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

 

39
 

 

Results of Operations

 

Years Ended December 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 Years Ended December 31, 
Dollars in thousands  2013   2012   Increase (decrease) 
  Dollars   Percent   Dollars   Percent   Dollars   Percent 
Revenue                             
Wholesale trading revenue, net  $25,305    77.2%  $18,256    95.7%  $7,049    38.6%
Retail electricity revenue   7,480    22.8%   818    4.3%   6,662    814.4%
Net revenue   32,785    100.0%   19,074    100.0%   13,711    71.9%
Operating costs & expenses                           
Cost of retail electricity sold   7,761    23.7%   764    4.0%   6,997    915.8%
Salaries, wages & related   13,244    40.4%   8,896    46.6%   4,348    48.9%
Professional fees   4,395    13.4%   3,183    16.7%   1,212    38.1%
Other general & administrative   2,853    8.7%   2,248    11.8%   605    26.9%
Trading tools & subscriptions   923    2.7%   945    4.9%   (22)   -2.3%
Total operating expenses   29,176    89.0%   16,036    84.1%   13,140    81.9%
Operating income   3,609    11.0%   3,038    15.9%   571    18.8%
Interest expense   (1,502)   -4.6%   (1,065)   -5.6%   (437)   41.0%
Interest income   31    0.1%   31    0.1%       0.0%
Loss on foreign currency exchange   2    0.0%   (17)   -0.1%   19    11.8%
Other expense, net   (1,469)   -4.5%   (1,051)   -5.5%   (418)   39.8%
Income before income taxes   2,140    6.5%   1,987    10.4%   153    7.7%
Income tax provision   9    0.0%   56    0.3%   (47)   -83.9%
Net income   2,131    6.5%   1,930    10.1%   201    10.4%
Preferred distributions   (549)   -1.7%   (503)   -2.6%   (46)   9.1%
Net income attributable to common  $1,582    4.8%  $1,427    7.5%  $155    10.9%

 

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

 

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

 

40
 

 

For the years ended December 31, 2013 and 2012, financial electricity represented 100% and 98% of our total trading volume in FERC-regulated markets compared to 0% and 2% for physical power. The table below details our open derivative contracts held for trading purposes as of the dates indicated:

 

Open Derivative Contracts Held for Trading

 

As of December 31, 2013

 

      Delivery    Final  Energy   Fair Value 
Contract type  Hub  period   settlement  (MWh)   Asset   Liability 
Electricity future  PJM West Hub peak   Dec 2013   1/3/14   4,000   $   $17,240 
Electricity future  PJM West Hub peak   Dec 2013   1/3/14   16,800        34,608 
Electricity future  PJM West Hub peak   Dec 2013   1/3/14   800        400 
Electricity future  ISO-NE Mass Hub peak   daily   1/4/14   800        18,400 
Electricity future  PJM West Hub peak   daily   1/6/14   1,600        3,200 
Electricity future  ISO-NE Mass Hub peak   daily   1/6/14   800    15,200     
Electricity future  ISO-NE Mass Hub peak mini   Jan 2014   2/4/14   5,280    792     
Electricity future  NYISO G peak mini   Jan 2014   2/4/14   3,520        8,096 
Electricity future  NYISO G off peak mini   Jan 2014   2/4/14   1,960    22,050     
Electricity future  AESO ext peak   Feb 2014   3/4/14   40,320        596,137 
Electricity future  AESO ext off peak   Feb 2014   3/4/14   19,040    614,592     
Electricity future  ISO-NE Mass Hub peak mini   Feb 2014   3/4/14   4,800    6,080     
Electricity future  NYISO G peak mini   Feb 2014   3/4/14   1,600        8,800 
Electricity future  NYISO G off peak mini   Feb 2014   3/4/14   1,760    16,104     
Electricity future  AESO ext off peak   Mar 2014   4/5/14   1,240        35,571 
Electricity future  PJM West Hub peak mini   Mar 2014   4/5/14   1,680        1,428 
Electricity future  PJM West Hub peak mini   Apr 2014   5/4/14   1,760        4,048 
Electricity future  PJM West Hub peak mini   May 2014   6/4/14   1,680        3,612 
Electricity future  PJM West Hub peak mini   Jun 2014   7/4/14   1,680    1,932     
Electricity future  PJM West Hub peak mini   Jul 2014   8/4/14   1,760    26,576     
Electricity future  PJM West Hub peak mini   Aug 2014   9/4/14   1,680    14,280     
Electricity future  PJM West Hub peak mini   Sep 2014   10/4/14   1,680        4,872 
Electricity future  PJM West Hub peak mini   Oct 2014   11/4/14   1,840        10,856 
Electricity future  PJM West Hub peak mini   Nov 2014   12/5/14   1,520        6,688 
Electricity future  PJM West Hub peak mini   Dec 2014   1/3/15   1,760        3,872 
     Totals             121,360   $717,606   $757,828 

 

As of December 31, 2012

 

       Contract  Final  Energy   Fair Value 
Contract type  Hub   period  settlement  (MWh)   Asset   Liability 
Electricity future  MISO Indiana Hub peak    daily   1/3/13   224   $15,704   $4,568 
Electricity future  MISO Indiana Hub off peak    daily   1/3/13   256        5,792 
Electricity future  PJM West Hub    daily   1/3/13   1,312    83,560    1,904 
Electricity future  AESO ext off peak    Feb 2013   3/4/13   1,120        43,819 
Electricity future  AESO ext peak    Apr 2013   5/4/13   24,000    459,858     
Electricity future  AESO ext off peak    Apr 2013   5/4/13   12,000        411,103 
Electricity future  AESO ext peak    Jul 2013   8/4/13   24,800    590,873     
Electricity future  AESO ext off peak    Jul 2013   8/4/13   12,400        572,214 
     Totals               76,112   $1,149,995   $1,039,400 

 

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 2013 were characterized by 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 or not we are buying or selling.

 

41
 

According to NOAA data, for 2013, heating degree-days for the U.S. were 4,519 or 19% above 2012’s figure of 3,789 and 4% above the 30 year normal of 4,327. Cooling degree-days during 2013 totaled 1,273 compared to 1,456 in 2012 and a normal of 1,308, making the year about 13% cooler than last year and about 3% cooler than normal.

 

For 2013, the Henry Hub natural gas spot price averaged $3.73/MCF, 35% above 2012’s $2.75 mark and 1% below the 5 year average price of $3.76. Supplies of gas during 2013 were adequate. Weekly storage levels averaged 2,784 BCF or 12% less than in 2012’s level of 3,159 but 3% higher than the 5 year average of 2,712.

 

  Years Ended December 31,
      Increase (decrease)
  Units   This year vs last year   This year vs LTA
  2013   2012   LTA (1)   Units   Percent   Units   Percent
U.S. Weather                          
Heating degree-days 4,519   3,789   4,327   730   19%   193   4%
Cooling degree-days 1,273   1,456   1,308   (183)   -13%   (34)   -3%
Avg temperature (°F) 52.4°F   55.7°F   53.7°F   -3.3°F   -6   -1.3°F   -2
Natural Gas                          
Henry Hub spot price ($/MCF 3.73   2.75   3.76   0.98   35%   (0.03)   -1%
Working gas in underground storage, Lower 48 states, EIA weekly estimates (BCF) 2.784   3.159   2.712   (375)   -12%   73   3%

____________________

1 - "LTA" abbreviates long term average. For weather data, the 30 year period is 1984-2012 and for natural gas the 5 year period is 2009-2013.

 

The average for the PJM West Peak price during 2013 was $43.26/MWh with a standard deviation of $14.69 resulting in a coefficient of variation of 34%, compared to $39.85/MWh, $11.94, and 30% for 2012. As shown by the table below, although price levels were generally higher in 2013, volatility as measured by daily percentage changes were generally lower in 2013 as compared to 2012.

 

  Years Ended December 31, 
PJM West Hub Peak Day Ahead          Increase (decrease) 
   2013   2012   Units   Percent 
Price ($/MWh)                    
Average   43.26    39.85    3.42    9% 
Maximum   153.85    127.26    26.59    21% 
Minimum   29.70    28.81    0.90    3% 
Standard deviation   14.69    11.94    2.76    23% 
Coefficient of variation (stdev ÷ avg)   34%    30%    4%    13% 
                     
Daily percentage changes                    
Average   1.0%    1.3%    -0.3%    -22% 
Maximum   127.6%    156.7%    -29.1%    -19% 
Minimum   -55.3%    -68.0%    12.7%    -19% 
Standard deviation   14.6%    16.8%    -2.1%    -13% 
                     
Number of days                    
Up 10% or more   48    55    (7)   -13% 
Between 10% up and 10% down   165    156    9    6% 
Down 10% or more   42    43    (1)   -2% 

 

 

42
 

Largely as a result of these factors, for the year ended December 31, 2013, net trading revenue increased by $7,049,000 or 38.6% to $25,305,000 compared to $18,256,000 for 2012.

 

On February 1, 2011, TCPH commenced a major restructuring of its Canadian operations. During the third quarter of 2012, management concluded that it was unlikely that the Canadian business would ever be able to provide an adequate return on investment, and consequently, on September 14, 2012, all operations ceased. During the year ended December 31, 2013, TCPC had no revenue and operating income of $4,500 due solely to refunds received as a result of cancelling certain subscriptions. During the year ended December 31, 2012, net revenue was $1,098,000 and operating income was $2,961,891. Operating income in 2012 was positively impacted by the reversal of compensation accruals for former employees totaling $2,361,685 and without such reversals, operating income would have been $600,206.

 

Retail electricity sales: 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 in 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.

 

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.

 

During 2013, we recognized revenue of $7,480,000 for the year compared to $818,000 for 2012, principally as a result of the increase in customers receiving service from us. 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 we did not enter into the retail business until June 29, 2012.

 

   For/at years ended December 31, 
Key Operating Statistics          Increase (decrease) 
   2013   2012   Units   Percent 
Revenues ($000s)   7,480    818    6,662    814.4% 
Unit sales (MWh)   99,231    11,464    87,766    765.5% 
Average retail price (¢/kWh)   7.54    7.14    0.40    5.6% 
                     
New customer sign-ups   9,278    3,602    5,676    157.6% 
Avg daily sign-ups   50.4    19.6    30.8    157.6% 
                     
Customers receiving service   9,822    3,219    6,603    205.1% 
Total load (MW)   28    11    18    169.4% 
Total avg daily use (MWh)   305    109    195    178.3% 
Avg load per customer (kW)   2.9    3.3    (0.4)   -11.7% 
Avg daily use per customer (kWh)   31.0    34.0    (3.0)   -8.8% 

 

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

 

43
 

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

 

During the year ended December 31, 2013, the Company recorded no revenue or income but capitalized a total of $784,000 of costs associated with its real estate development activities, consisting primarily of purchases of land for development.

 

Costs of retail electricity sold: Our costs of electricity sold includes the cost of purchased power, EDC service fees, renewable energy certificates, bad debt expense, and gains net of losses and commissions on derivative contracts used to hedge power purchase costs. For 2013, the Company purchased substantially 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 “cash in trading accounts”.

 

In our retail business, we are exposed to volatility in the cash cost of the energy acquired for sale to customers. For 2013, we hedged the cost of 103,280 MWh or 105% of the 98,718 MWh of electricity sold to our retail customers in such period, compared to 5,120 MWh or 52% of the 9,754 MWh sold to retail customers in 2012. For 2013 and 2012, our hedges had the effect of decreasing cost of retail electricity sold by $247,290 and $5,683, respectively.

 

As of December 31, 2013, we had hedged the cost of 32,760 MWh (approximately 32% of expected 2014 electricity purchases for the customers receiving service from us as of that date) and $357,000, representing the 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 retail electricity sold by December 31, 2014.

 

We have designated the derivative contracts detailed below as cash flow hedges for a portion of our expected 2014 cash power purchases for retail.

 

Open Derivative Contracts Designated as Cash Flow Hedges

As of December 31, 2013

 

             Fair Value 
Contract type  Hub  Delivery period  Energy
(MWh)
   Asset   Liability 
Electricity futures  ISO-NE Mass Hub  Q1 2014   12,200   $289,338   $ 
Electricity futures  ISO-NE Mass Hub  Q2 2014   8,560    2,436    24,564 
Electricity futures  ISO-NE Mass Hub  Q3 2014   5,120    11,588    252 
Electricity futures  ISO-NE Mass Hub  Q4 2014   6,880    113,948    35,880 
Totals         32,760   $417,310   $60,696 

 

Salaries, wages, and related expenses: Salaries, wages, 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 2013, salaries, wages, and related costs increased by $4,348,000 or 48.9% to $13,244,000 compared to $8,895,000 for 2012. Our personnel expense is directly related to the revenue we record, since our trader’s compensation is tied to revenue production.

 

44
 

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

 

For 2013, professional fees increased by $1,212,000 to $4,395,000 compared to $3,183,000 in 2012. The increase was due primarily to the addition of a trading consultant at CTG. The Company also continues to incur legal fees in connection with the Canadian former employee litigation and the FERC investigation.

 

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 2013, these costs increased by approximately $605,000 to $2,853,000 compared to $2,248,000 for 2012. The increase were primarily related to marketing costs and administrative expenses associated with the Notes Offering and certain costs related to our retail business such as contract fees, office expenses, and travel that did not exist for a full year in 2012.

 

In addition, depreciation and amortization is included in other general and administrative expenses and increased by $306,000 to $557,000 from $251,000 due to the amortization of the non-compete agreement that began on January 1, 2013, a full year of amortization of deferred financing costs, and a full year of amortization of certain intangible assets acquired in connection with the CP&U transaction.

 

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 year ended December 31, 2013, trading tools and subscriptions expense decreased by $22,000 or 2.4% to $923,000 compared to $945,000 for 2012. Contracts renew over time and during 2013, fewer contracts were renewed thus dropping the expense.

 

Other income (expense): Other expense, net of other income, increased by $418,000 to $1,469,000 for 2013 compared to $1,051,000 for 2012. As the principal component of other expense, interest expense increased by $437,000 to $1,502,000 for the year from $1,065,000 during 2012. The increase was attributed primarily to an increase of $3,905,000 in outstanding debt from $6,280,000 at December 31, 2012 compared to $10,185,000 at December 31, 2013, due principally to net new issuances of Notes during 2013.

 

Provision for taxes: The tax provision is directly related to foreign income taxes associated with TCPC.

 

Preferred distributions: During 2013, we distributed $549,000 to preferred unit holders compared to $503,000 in 2012, due solely to the issuance date of the redeemable preferred on January 31, 2012.

 

45
 

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 as well as margin requirements associated with hedges. We are generally required to pay for power every 4 days or so, while our average collection period on receivables is 40 to 45 days. As such, our capital is largely invested in trading accounts and deposits and receivables. Our capital expenditure requirements are nominal, being limited to computer and office equipment, software, and office furniture. Therefore, in any given reporting period, the amount of cash consumed or generated will primarily be due to changes in working capital.

 

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

 

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

 

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

 

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

 

46
 

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

 

   At December 31,         
   2013   2012   Increase (decrease) 
Dollars in thousands  Dollars   Percent of total assets   Dollars   Percent of total assets   Dollars   Percent 
                         
Liquidity                              
Cash - unrestricted  $3,190    18.2%   $772    4.7%   $2,418    313.3% 
Cash in trading accounts   10,484    59.7%    12,025    73.9%    (1,541)   -12.8% 
Accounts receivable - trade   1,315    7.5%    2,191    13.5%    (876)   -40.0% 
Total liquid assets   14,990    85.4%    14,988    92.2%    2    0.0% 
Total assets  $17,562    100.0%   $16,263    100.0%    1,299    8.0% 
                               
Capital Resources                              

Notes payable

                              
Demand or current  $5,123    29.2%   $5,006    30.8%   $117    2.3% 
Long term   5,062    28.8%    1,274    7.8%    3,788    297.3% 
Total notes payable   10,185    58.0%    6,280    38.6%    3,905    62.2% 
                               
Redeemable preferred       0.0%    2,745    16.9%    (2,745)   -100.0% 
Series A preferred   2,745    15.6%        0.0%    2,745    na   
Common   2,003    11.4%    3,654    22.5%    (1,651)   -45.2% 
Total redeemable preferred & equity   4,748    27.0%    6,399    39.3%    (1,651)   -25.8% 
Total capitalization  $14,933    84.9%   $12,679    78.0%   $2,254    17.8% 

 

The table below summarizes our primary sources and uses of cash for the years ended December 31, 2013 and 2012 as derived from the statements of cash flows included in this Form 10-K.

 

   For the Years Ended December 31, 
Dollars in thousands          Increase (decrease) 
   2013   2012   Dollars   Percent 
Net cash provided by (used in):                    
Operating activities  $4,350   $2,889   $1,461    50.6% 
Investing activities   (1,309)   (289)   (1,020)   352.9% 
Financing activities   (386)   (2,814)   2,428    -86.3% 
Net cash flow   2,655    (214)   2,869    1240.6% 
                     
Effect of exchange rate changes on cash   (236)   14    (250)   -1785.7% 
                     
Cash - unrestricted:                    
Beginning of period   772    971    (200)   -20.5% 
End of period  $3,190   $771   $2,419    313.8% 

 

At December 31, 2013, our debt totaled $10,185,000 compared to $6,280,000 as of the prior year end. We generated $4,350,000 from operating activities and used $1,309,000 for investments in equipment, furniture, land held for development, and other assets, including restricted cash. We used $386,000 for financing activities, including a net $3,655,000 increase in debt and payments of $4,041,000 in distributions. Of the total distribution amount, $549,000 was paid to the holder of our preferred units and $3,492,000 was paid to our common unit-holders.

 

47
 

At December 31, 2012, our debt totaled $6,280,000 compared to $10,288,000 as of the prior year end. During 2012, we converted $2,745,000 of debt to redeemable preferred units in a non-cash transaction. We generated $2,889,000 from operating activities and used $289,000 for investments in equipment and furniture and to acquire the business and certain assets of CP&U. We used $2,814,000 for financing activities, including an increase of $394,000 in deferred financing costs, a $1,263,000 net reduction in debt, $1,057,000 in distributions, and a $100,000 payment for redemption of 1,540 of our common units. Of the total distribution amount, $503,000 was paid to the holder of our preferred units and $554,000 was paid to our common unit-holders.

 

Financing

 

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.

 

The Margin Agreement was amended on May 31, 2013 to reduce the uncommitted credit line to $15,000,000, the commitment fee to $25,000 per month, and the covenant with respect to net liquidating equity as defined to $1,500,000.

 

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 years ended December 31, 2013 and 2012, we incurred $1,113,000 and $651,000, respectively, of offering-related expenses, including marketing and printing expense, legal and accounting fees, filing fees, and trustee fees. These costs and expenses are expensed as incurred.

 

From the effective date of May 10, 2012 through March 27, 2014, we have sold a total of $12,623,326 in principal amount of Notes and repaid $844,752, for a net raise to date of $11,778,574.

 

Effective January 31, 2012, TCP sold certain financial rights, but not governance rights, to 496 new membership units, which we refer to as “redeemable preferred units”, to John 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 paid Mr. Hanson and his designee a guaranteed distribution of $45,750 per month.

 

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

 

48
 

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.

 

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

 

49
 

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 years ended December 31, 2013 and 2012, we recorded $4,300,561 and $3,047,294, 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 December 31, 2013 and 2012 was $169,798 and $777,955, respectively.

 

Item 7A - Quantitative and Qualitative Disclosures about Market Risk

 

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

 

Commodity Price Risk

 

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. We manage the commodity price risk of our retail load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges as well as over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.

 

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

 

50
 

The following table summarizes our VaR as of and for the years ended December 31, 2013, and 2012:

 

           Increase (decrease) 
   2013   2012   Units   Percent 
Dollars                    
As of December 31  $111,141   $98,756   $12,385    12.5% 
                     
For the year ended December 31:                    
Average  $108,743   $101,467   $7,276    7.2% 
Maximum   409,379    385,712        6.1% 
Minimum   5,985        5,985    na   
                     
Percent of cash in trading accounts                    
As of December 31   1.06%    0.82%    0.24%    29.1% 
                     
For the year ended December 31:                    
Average (1)   0.97%    0.84%    0.12%    14.5% 
Maximum (1)   3.64%    3.21%    0.43%    13.4% 
Minimum (1)   0.05%    0.00%    0.05%    na   

____________

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

 

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

 

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

 

   Average percentage
change in MTM valuation
   Dollar
change in MTM valuation
 
Percentage change in forward price
from December 31, 2013
  Cash flow
hedges
   Derivatives held
for trading
   Cash flow
hedges
   Derivatives held
for trading
 
10%   -68.2%    46.7%    317,778    671,382 
5%   -34.1%    23.4%    158,889    335,691 
1%   -6.8%    4.7%    31,778    67,138 
-1%   6.8%    -4.7%    (31,778)   (67,138)
-5%   34.1%    -23.4%    (158,889)   (335,691)
-10%   68.2%    -46.7%    (317,778)   (671,382)

 

Interest Rate Risk

 

Although we currently have no variable rate debt, in the future we may be exposed to fluctuations in interest rates through the issuance of such obligations. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars, and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument.

 

51
 

 

Liquidity Risk

 

Liquidity risk arises from our general funding needs and the management of our assets and liabilities. We are exposed to additional collateral posting or margin requirements with the ISOs and exchanges if price volatility or levels increase. Based on a sensitivity analysis for positions under marginable contracts, a 20% increase in electricity prices would cause a change in margin collateral posted of approximately $438,000 as of December 31, 2013. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2013.

 

Wholesale Counterparty Credit Risk

 

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

 

Retail Customer Credit Risk

 

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

 

Foreign Exchange Risk

 

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

 

52
 

 

Item 8 – Financial Statements and Supplementary Data

 

Management’s Report on Internal Controls over Financial Reporting

 

To the Board of Governors and Members

Twin Cities Power Holdings, LLC and Subsidiaries

Lakeville, Minnesota

 

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued in 2009 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under that framework, management concluded that our internal control over financial reporting was effective as of December 31, 2013.

 

A control system, no matter how well-designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. In addition, the design of any system of controls is based in part on certain assumptions about the likelihood of future events, and controls may become inadequate if conditions change. There can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

 

This annual report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

 

53
 

 

Report of Independent Registered Public Accounting Firm

 

To the Board of Governors and Members

Twin Cities Power Holdings, LLC and Subsidiaries

Lakeville, Minnesota

 

We have audited the accompanying consolidated balance sheets of Twin Cities Power Holdings, LLC and Subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of comprehensive income, members’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of its internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Twin Cities Power Holdings, LLC and Subsidiaries as of December 31, 2013 and 2012, and the results of their operations and cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

 

 

 

/s/ Baker Tilly Virchow Krause, LLP   

Minneapolis, Minnesota

March 28, 2014

 

54
 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Balance Sheets

As of December 31, 2013 and 2012

 

   2013   2012 
Assets        
Current assets          
Cash - unrestricted  $3,190,495   $771,852 
Cash in trading accounts   10,484,448    12,025,023 
Accounts receivable - trade   1,315,209    2,191,267 
Note receivable   140,964     
Marketable securities   256,004     
Prepaid expenses and other current assets   242,482    189,808 
Total current assets   15,629,602    15,177,950 
           
Equipment and furniture, net   504,298    571,232 
           
Other assets          
Intangible assets, net   305,978    125,326 
Deferred financing costs, net   337,559    388,979 
Cash - restricted   320,188     
Land held for development   110,477     
Mortgage note receivable   353,504     
Total assets  $17,561,606   $16,263,487 
           
Liabilities and Members' Equity          
Current liabilities          
Accounts payable - trade  $1,035,644   $1,469,301 
Accrued expenses   683,556    70,378 
Accrued compensation   299,439    1,984,388 
Accrued interest   359,758    44,472 
Accrued distributions       15,867 
Notes payable, related parties       866,665 
Notes payable   200,000    3,400,262 
Renewable unsecured subordinated notes   4,922,596    738,693 
Obligations under non-competition agreement   250,000     
Total current liabilities   7,750,993    8,590,026 
           
Long-term debt          
Renewable unsecured subordinated notes   5,062,230    1,274,445 
Total liabilities   12,813,223    9,864,471 
           
Commitments and contingencies          
Redeemable preferred units       2,745,000 
Members' equity          
Series A preferred equity   2,745,000     
Common equity   1,302,994    3,196,737 
Accumulated other comprehensive income   700,389    457,279 
Total members' equity   4,748,383    3,654,016 
Total liabilities and members' equity  $17,561,606   $16,263,487 

 

See notes to consolidated financial statements.

 

55
 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Comprehensive Income

For the Years Ended December 31, 2013 and 2012

 

   2013   2012 
Revenue          
Wholesale trading revenue, net  $25,305,723   $18,255,932 
Retail electricity revenue   7,479,775    817,641 
    32,785,498    19,073,573 
Costs and expenses          
Cost of retail electricity sold   7,760,674    763,943 
Retail sales and marketing   493     
Compensation and benefits   13,243,841    8,895,451 
Professional fees   4,394,676    3,183,118 
Other general and administrative   2,853,517    2,248,056 
Trading tools and subscriptions   922,756    945,198 
    29,175,957    16,035,766 
Operating income   3,609,541    3,037,807 
           
Other income (expense)          
Interest expense   (1,501,935)   (1,065,414)
Interest income   30,272    31,020 
Gain (loss) on foreign currency exchange   2,261    (16,678)
    (1,469,402)   (1,051,072)
Income before income taxes   2,140,139    1,986,735 
Income tax provision   8,823    56,124 
           
Net income   2,131,316    1,930,611 
Distributions - preferred   (549,036)   (503,250)
           
Net income attributable to common   1,582,280    1,427,361 
           
Other comprehensive income (loss)          
Foreign currency translation adjustment   (201,303)   (84,356)
Change in fair value of cash flow hedges   438,646    (82,032)
Unrealized gain on investment securities   5,767     
           
Comprehensive income  $1,825,390   $1,260,973 

 

See notes to consolidated financial statements.

 

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Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2013 and 2012

 

   2013   2012 
Cash flows from operating activities        
Net income  $2,131,316   $1,930,611 
Adjustments to reconcile net income to net cash provided by operating activities:          
Loss on sale of equipment and furniture   14,802    18,467 
Depreciation and amortization   557,035    250,674 
(Increase) decrease in:          
Trading accounts and deposits   2,013,968    3,734,904 
Accounts and notes receivable   876,059    (1,576,792)
Prepaid expenses and other assets   (52,674)   581,665 
Increase (decrease) in:          
Accounts payable - trade   (433,664)   94,263 
Accrued expenses   613,178    61,794 
Accrued compensation   (1,684,949)   (2,105,550)
Accrued interest   315,286    (100,697)
Net cash provided by operating activites   4,350,357    2,889,339 
           
Cash flows from investing activities          
Purchase of marketable securities   (250,237)    
Advance on note receivable   (140,964)    
Purchase of equipment and furniture   (134,135)   (128,728)
Purchase of land held for development   (110,477)    
Purchase of mortgage note receivable   (353,504)    
Advance to restricted cash   (320,188)    
Purchase of intangible assets       (160,000)
Net cash used in investing activities   (1,309,505)   (288,728)
           
Cash flows from financing activities          
Deferred financing costs       (393,990)
Payments on notes payable   (4,316,927)   (3,276,338)
Renewable unsecured subordinated notes:          
Issuances   8,625,775    2,094,138 
Redemptions   (654,087)   (81,000)
Distributions - preferred   (549,036)   (503,250)
Distributions - common   (3,491,890)   (553,761)
Redemption of common units       (100,000)
Net cash used in financing activities   (386,165)   (2,814,201)
           
Net increase (decrease) in cash   2,654,687    (213,590)
Effect of exchange rate changes on cash   (236,044)   14,361 
           
Cash - unrestricted          
Beginning of year   771,852    971,081 
End of year  $3,190,495   $771,852 

 

See notes to consolidated financial statements.

 

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Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Cash Flows (Continued)

For the Years Ended December, 31 2013 and 2012

 

   2013   2012 
Non-cash investing and financing activities:          
Effective portion of cash flow hedges  $356,614   $82,032 
           
Obligations under non-competition agreement  $500,000   $ 
           
Series A preferred units issued in exchange for redeemable preferred units  $2,745,000   $ 
           
Redeemable preferred units issued in exchange for certain notes payable  $   $2,745,000 
           
Accrued distributions - common  $   $15,867 
           
Unrealized gain on investment securities  $5,767   $ 
           
Supplemental disclosures of cash flow information:          
Cash payments for interest  $1,186,649   $1,166,111 
           
Cash payments for income taxes, net  $8,823   $ 

 

 

See notes to consolidated financial statements.

 

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Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Changes in Members’ Equity

For the Years ended December 31, 2013 and 2012

 

   Series A Preferred Equity   Common
Equity
   Accumulated Other Comprehensive Income   Total 
Balance - December 31, 2011  $   $2,439,004   $623,667   $3,062,671 
                     
Redemption of common units       (100,000)       (100,000)
                     
Net income       1,930,611        1,930,611 
                     
Other comprehensive loss           (166,388)   (166,388)
                     
Distributions - preferred       (503,250)       (503,250)
                     
Distributions - common       (569,628)       (569,628)
                     
Balance - December 31, 2012  $   $3,196,737   $457,279   $3,654,016 
                     
Issued in exchange for redeemable preferred units   2,745,000            2,745,000 
                     
Net income       2,131,316        2,131,316 
                     
Other comprehensive income           243,110    243,110 
                     
Distributions - preferred       (549,036)       (549,036)
                     
Distributions - common       (3,476,023)       (3,476,023)
                     
Balance - December 31, 2013  $2,745,000   $1,302,994   $700,389   $4,748,383 

 

See notes to consolidated financial statements.

 

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Twin Cities Power Holdings, LLC and Subsidiaries

 

Notes to Consolidated Financial Statements

 

1.Organization

 

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

 

Through its wholly-owned subsidiaries, the Company maintains market-based rate authority granted by FERC and trades financial power in wholesale electricity markets managed by Independent System Operators or Regional Transmission Organizations and regulated by FERC (collectively, “ISOs”) including those managed by the Midcontinent Independent System Operator (“MISO”), the PJM Interconnection (“PJM”), ISO New England (“ISO-NE”), and the New York Independent System Operator (“NYISO”). We also are members of the Electric Reliability Council of Texas (“ERCOT”) which is an ISO regulated by the Texas Public Utilities Commission and the Texas Legislature. The Company also trades electricity and other energy-related commodities and derivatives on exchanges operated by the Intercontinental Exchange® (“ICE”), the Natural Gas Exchange Inc. (“NGX”), and the CME Group (“CME”) which are regulated the Commodity Futures Trading Commission (“CFTC”). The Company entered the retail energy services business in 2012 via the acquisition of certain assets and the business of a small retail energy supplier and in 2013, the Company entered the residential real estate development business. Consequently, the Company has three business segments used to measure its activity – wholesale trading, retail energy services, and real estate development.

 

The Operating Companies

 

TCP was formed on January 1, 2007 and currently has the following subsidiaries:

·Vision Consulting, LLC was formed on April 4, 2009 and discontinued operations in June 2011.
·TC Energy Trading, LLC was formed on May 22, 2009 and is currently inactive.
·Chesapeake Trading Group, LLC (“CTG”) was formed on June 16, 2009 and is currently active.
·Summit Energy, LLC, (“SUM”) was formed on December 4, 2009 and has two classes of members - a voting class, Class A, and a non-voting class, Class B. TCP owns 100% of the Class A units, which represent 100% of the equity interest in SUM. The rights of Class B members are limited to specific allocations of income and loss as set forth in the member control agreement and are recorded as profits interests in the year earned. Accordingly, the accompanying balance sheets and statements of comprehensive income do not reflect a non-controlling interest related to Class B members.

 

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CP was formed on March 14, 2008. CP is consolidated with Cygnus Energy Futures, LLC (“CEF”) which was formed on July 24, 2007. CEF has two classes of members - a voting class, Class A, and a non-voting class, Class B. CP owns 100% of CEF’s Class A member units, which represent 100% of the equity interest in CEF. The rights of Class B members are limited to specific allocations of income and loss as set forth in the member control agreement and are recorded as profits interests in the year earned. Accordingly, the accompanying balance sheets and statements of comprehensive income do not reflect a non-controlling interest related to Class B members.

 

TCE was formed on March 27, 2008. TCE is consolidated with Twin Cities Power – Canada, Ltd. (“TCPC”), which was formed on January 29, 2008 as a Canadian unlimited liability corporation and converted to a regular Alberta corporation in February 2012. On February 1, 2011, TCPH commenced a major restructuring of the operations of TCPC. During the third quarter of 2012, after review of the progress of the restructuring, the potential implications of the FERC investigation, and the outlook for the subsidiary, management concluded that it was unlikely that TCPC would ever be able to provide an adequate return. Consequently, on September 5, 2012, TCE resolved that TCPC should cease all operations on September 14, 2012. TCPC’s remaining employee was terminated and he became an independent contractor to the Company; its remaining fixed assets were transferred, the office lease was abandoned; the process of canceling or withdrawing its permits and licenses issued by Canadian energy regulatory authorities was initiated; and all accounts were closed except for two bank accounts. See also “Note 18 - Commitment and Contingencies”.

 

During the year ended December 31, 2013, TCPC had no revenue and operating income of $4,500 due solely to refunds received as a result of cancelling certain insurance policies and trading subscriptions. During 2012, net revenue was $1,098,000 and operating income was $2,961,891. Operating income in 2012 was positively impacted by the reversal of compensation accruals for former employees totaling $2,361,685, and without such reversals, operating income would have been $600,206.

 

On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC, a retail energy supplier serving residential and small commercial markets in Connecticut. The business was re-named 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 but effective June 1, 2013, TSE was reorganized as a wholly-owned subsidiary of the Company and on October 25, 2013, in anticipation of the receipt of FERC approval of the Company’s acquisition of Discount Energy Group, LLC (“DEG”), a retail energy business licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio, the Company formed a new first-tier subsidiary, Retail Energy Holdings, LLC (“REH”), and transferred the ownership of TSE to this entity. FERC approval of the acquisition of DEG was received on December 13, 2013 and the transaction closed on January 2, 2014.

 

On October 23, 2013, the Company formed Cyclone Partners, LLC (“Cyclone”) as a wholly-owned subsidiary to take advantage of certain investment opportunities believed to be present in the residential real estate market, particularly in the southern portion of the Minneapolis-St. Paul metropolitan area.

 

2.Summary of Significant Accounting Policies

 

Consolidation

 

The accompanying consolidated financial statements include all of the accounts of the Company and its first and second-tier subsidiaries. Intercompany transactions and balances have been eliminated.

 

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Use of Estimates

 

Preparation of the consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts for revenue and expenses during the reported period. Actual results could differ from those estimates.

 

Cash

 

Cash include highly liquid investments with an original maturity of three months or less at the time of purchase.

 

Revenue Recognition

 

Wholesale Trading

 

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

 

Retail Energy Services

 

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

 

Real Estate Development

 

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

 

Derivative Instruments

 

In our wholesale operations, we use derivative contracts for trading purposes, seeking to profit from perceived opportunities driven by expected changes in market prices. In our retail business, the Company is exposed to volatility in the cost of energy acquired for sale to customers, and as a result, we use derivatives to hedge or reduce this variability.

 

Our retail operations follow ASC 815, Derivatives and Hedging (“ASC 815”) guidance that permits “hedge accounting” under which the effective portion of gains or losses from the derivative and the hedged item are recognized in earnings in the same period. To qualify for hedge accounting, the hedge relationships must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis.

 

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“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.

 

Financial Instruments

 

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

 

Foreign Currencies

 

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

 

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 gains of $2,261 and losses of $16,678 for the years ended December 31, 2013 and 2012, respectively.

 

Concentrations of Credit Risk

 

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

 

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

 

Fair Value

 

The fair values of the Company’s cash, accounts receivable, and accounts payable were considered to approximate their carrying values at December 31, 2013 and 2012 due to the short-term nature of the accounts.

 

Management believes the carrying values of the Company’s notes payable and Renewable Unsecured Subordinated Notes reasonably approximate their fair value at December 31, 2013 and 2012 due to the relatively new age of these particular instruments. No assessment of the fair value of these obligations has been completed and there is no readily available market price.

 

See also “Note 8 – Fair Value Measurements”.

 

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Accounts Receivable

 

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 December 31, 2013 or 2012.

 

Marketable Securities

 

The Company classifies its investments in marketable securities as “available-for-sale”. Available-for-sale securities are required to be carried at their fair value, with unrealized gains and losses that are considered temporary in nature recorded in “accumulated other comprehensive income”. The Company periodically evaluates its investments in marketable securities for impairment due to declines in market value considered to be other than temporary. Such impairment evaluations include, in addition to persistent, declining market prices, general economic and Company-specific evaluations. If the Company determines that a decline in market value is other than temporary, then a charge to operations is recorded in “other expense” and a new cost basis in the investment is established.

 

Equipment and Furniture

 

Equipment and furniture are carried at cost and additions or replacements are capitalized. The cost of equipment disposed of or retired and the related accumulated depreciation are eliminated from the accounts with any gain or loss included in operations. Equipment, computers, internally-developed software, and furniture are depreciated using the straight-line method over the estimated useful lives of the assets that range from 3 to 7 years. Leasehold improvements are depreciated using the straight-line method over the shorter of the lease term, or the estimated useful life of the asset. Expenditures for repairs and maintenance are charged to expense as incurred.

 

Land Held for Development

 

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

 

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. See “Note 10 - Intangible Assets”.

 

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Impairment of Long-Lived Assets

 

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

 

Profits Interests

 

Specific second-tier subsidiaries of the Company have Class B members. Under the terms of the subsidiaries’ member control agreements, Class B members have no voting rights, are not required to contribute capital, and have no rights to distributions following termination of employment, but are entitled to a defined share of profits while employed. Since Class B members have no corporate governance rights or risk of capital loss (or gain), they do not own non-controlling equity interests 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 years ended December 31, 2013 and 2012, the Company included $4,300,561 and $3,047,294, respectively, in compensation and benefits representing the allocation of profits interests to Class B members.

 

Income Taxes

 

The Company’s subsidiaries are not taxable entities for U.S. 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.

 

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

 

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

 

The Company’s federal and state tax returns are potentially open to examinations for the years 2009 through 2013 and its Canadian tax returns are potentially open to examination for the years 2010 through 2013.

 

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 were under review by the Department. The final audit report was issued by the Department on May 29, 2013. The results of the final audit had no impact on the financial position or results of operations of the Company.

 

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On October 24, 2013 a letter from the Minnesota Department of Revenue was received notifying the Company that TCP has been selected for a sales and use tax audit. The period under audit was July 1, 2010 through September 30, 2013. The final audit report was issued by the Department on January 7, 2014. The results of the final audit had no impact on the financial position or results of operations of the Company.

 

On October 24, 2013, a letter from the Canada Revenue Agency was received notifying the Company that refund requests for the years 2009-2011 submitted by TCE on June 3, 2013 have been referred to the Non-Resident Audit Division for further review.

 

New Accounting Pronouncements

 

Effective January 1, 2013, the Company adopted ASU No. 2013-02, 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 AOCI on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety. For other amounts that are not required to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. The adoption of the standard did not have a material impact on the Company’s financial statements.

 

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. This guidance will be effective prospectively for fiscal years beginning on or after December 15, 2013, which will be the Company's fiscal year 2014, with early adoption permitted. The Company has not yet evaluated the impact adoption of the guidance will have on the Company's consolidated financial statements.

 

3.Cash

 

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

 

Restricted cash on our balance sheet at December 31, 2013 and 2012 was $320,188 and zero, respectively, consisting of cash held in an escrow account with the City of Lakeville. The cash is being held as security with respect to the future development by Cyclone for the Fox Meadows property.

 

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

 

   December 31,   December 31, 
   2013   2012 
Credit requirement  $2,185,175   $3,445,912 
Available credit   8,299,273    8,579,111 
Cash in trading accounts  $10,484,448   $12,025,023 

 

4.Accounting for Derivatives and Hedging Activities

 

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

 

   Fair Value 
   Asset
Derivatives
   Liability
Derivatives
 
At December 31, 2013          
Designated as cash flow hedges:          
Energy commodity contracts  $417,310   $(60,695)
           
Not designated as hedging instruments:          
Energy commodity contracts   717,606    (757,828)
Total derivative instruments   1,134,916    (818,523)
Cash deposits in collateral accounts   10,168,055     
Cash in trading accounts, net  $11,302,971   $(818,523)
           
At December 31, 2012          
Designated as cash flow hedges:          
Energy commodity contracts  $63,571   $(158,880)
Not designated as hedging instruments:          
Energy commodity contracts   1,149,995    (1,039,400)
Total derivative instruments   1,213,566    (1,198,280)
Cash deposits in collateral accounts   12,009,737     
Cash in trading accounts, net  $13,223,303   $(1,198,280)

 

In 2012, the Company hedged the cost of 5,120 MWh or 52% of the 9.754 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”). This amount was reclassified to cost of energy sold by December 31, 2013.

 

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In 2013, the Company hedged the cost of 103,280 MWh or 105% of the 98,718 MWh of electricity sold to its retail customers in such period. As of December 31, 2013, we had hedged the cost of 32,760 MWh (approximately 32% of expected 2014 electricity purchases for the customers receiving service from us as of that date) and $356,614 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, 2014.

 

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

 

   Gain (Loss) Recognized in AOCI   Income Statement Classification  Gain (Loss) Reclassified from AOCI 
Year Ended
December 31, 2013
             
Cash flow hedges  $685,936   Cost of energy sold  $247,290 
              
Year Ended
December 31, 2012
             
Cash flow hedges  $(82,032)  Cost of energy sold  $5,683 

 

The following table provides details with respect to changes in AOCI as presented in our consolidated balance sheets, including those relating to our designated cash flow hedges, for the period from January 1, 2012 to December 31, 2013:

 

   Foreign
Currency
   Cash Flow
Hedges
   Available for
Sale Securities
   Total 
Balance - December 31, 2011  $623,667   $   $   $623,667 
Other comprehensive income (loss) before reclassifications   (84,356)   (82,032)       (166,388)
Net current period other comprehensive income (loss)   (84,356)   (82,032)       (166,388)
                     
Balance - December 31, 2012  $539,311   $(82,032)  $   $457,279 
Other comprehensive income (loss) before reclassifications   (201,303)   685,936    5,767   $490,400 
Amounts reclassified from AOCI       (247,290)       (247,290)
Net current period other comprehensive income (loss)   (201,303)   438,646    5,767    243,110 
                     
Balance - December 31, 2013  $338,008   $356,614   $5,767   $700,389 

 

5.Accounts Receivable

 

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.

 

   December 31,   December 31, 
   2013   2012 
Wholesale trading  $168,953   $1,756,926 
Retail energy services - billed   944,100    235,996 
Retail energy services - unbilled   202,156    198,345 
Accounts receivable - trade  $1,315,209   $2,191,267 

 

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As of December 31, 2013, there were two individual accounts in the Company’s retail energy services segment with receivable balances greater than 10% that aggregated 87% 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.Notes Receivable

 

The note receivable at December 31, 2013 consisted of $140,000 advanced to DEG on November 25, 2013. The note bears interest at 8.00% and is payable in monthly installments on the last day of each month. The note was repaid on January 2, 2014 upon closing of the acquisition of DEG. See “Note 20 - Subsequent Events”.

 

7.Marketable Securities

 

The following table shows the cost and estimated fair value of available-for-sale securities at December 31, 2013:

 

   Cost   Gross
Unrealized
Gains
   Gross
Unrealized
Losses
   Fair
Value
 
U.S. equities  $224,415   $5,836   $   $230,251 
International equities   25,047        (69)   24,978 
Money market fund   775            775 
Total  $250,237   $5,836   $(69)  $256,004 

 

The Company had no sale of securities and realized no impairment charges during 2013.

 

The following table shows the unrealized losses on, and fair value of, securities positions by the length of time such assets were in a continuous loss position as of December 31, 2013:

 

   Less than Twelve Months 
   Unrealized
Losses
   Fair
Value
 
International equities  $(69)  $24,978 

 

8.Fair Value Measurements

 

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

 

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

 

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

 

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

 

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Financial instruments categorized as Level 1 holdings are publicly traded in liquid markets with daily quotes and include exchange-traded derivatives such as futures contracts and options, certain highly-rated debt obligations, and some equity securities. Holdings such as shares in money market mutual funds that are based on net asset values as derived from quoted prices in active markets of the underlying securities are also classified as Level 1. The fair values of financial instruments that are not publicly traded in liquid markets, but do have characteristics similar to observable market information such as wholesale commodity prices, interest rates, credit margins, maturities, collateral, and the like upon which valuations are based are categorized in Level 2. Financial instruments that are not traded in publicly quoted markets or that are acquired based on prices and terms determined by direct negotiation with the issuer are classified as Level 3 and carried at book value until circumstances otherwise dictate. From time to time, the Company may engage third parties such as appraisers, brokers, or investment bankers to assist management in its valuation and classification of financial instruments.

 

The methods described above may produce fair value calculations that may not be indicative of net realizable value or reflective of future fair values. Furthermore, the use of different methodologies or assumptions to determine fair values could result in different fair value measurements and such variations could be material. There have been no changes in the methodologies used since December 31, 2012.

 

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

 

   Level 1   Level 2   Level 3   Total 
December 31, 2013                    
Cash in trading accounts, net  $10,484,448   $   $   $10,484,448 
Investment securities   256,004            256,004 
Mortgage note receivable           353,504    353,504 
                     
December 31, 2012                    
Cash in trading accounts, net  $12,025,023   $   $   $12,025,023 

 

There were no transfers during the year ended December 31, 2013 between Levels 1 and 2. The following table reconciles beginning and ending Level 3 fair value financial instrument balances for the year ended December 31, 2013:

 

Fair Value Measurement Using Significant Unobservable Inputs (Level 3) 
 
Balance - December 31, 2012  $ 
      
Total gains and losses:     
Included in other comprehensive income    
Included in earnings    
Purchases   353,504 
Sales    
Transfers into Level 3    
Transfers out of Level 3    
      
Balance - December 31, 2013  $353,504 
      
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held as of December 31, 2013  $ 

 

 

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9.Equipment and Furniture

 

Equipment, software, furniture, and leasehold improvements consisted of the following at December 31:

 

   2013   2012 
Equipment and software  $735,326   $734,431 
Furniture   291,958    283,196 
Leasehold improvements   192,561    186,314 
Equipment and furniture, gross   1,219,845    1,203,941 
Less: accumulated depreciation   (715,547)   (632,709)
Equipment and furniture, net  $504,298   $571,232 

 

Depreciation expense was $186,267 and $210,989 for the years ended December 31, 2013 and 2012, respectively.

 

10.Intangible Assets

 

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

 

The fair value of these intangible assets was based on significant inputs that are not observable in the market 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 sale of his units to Timothy S. Krieger, the Company’s founder, Chairman, Chief Executive Officer, and controlling member, the Company entered into a Non-Competition Agreement (the “NCA”) with David B. Johnson, a current governor of the Company valued at $500,000, to be amortized and paid in equal installments over 24 months.

 

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   December 31,   December 31, 
   2013   2012 
Acquisition of CP&U  $160,000   $160,000 
Non-competition agreement   500,000     
Less: accumulated amortization   (354,022)   (34,674)
Intangible assets, net  $305,978   $125,326 

 

Total amortization of intangible assets for the years ended December 31, 2013 and 2012 was $319,348 and $34,674, respectively and is included in other general and administrative expenses.

 

11.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 Notes sold, exclusive of any expected renewals.

 

   December 31,   December 31, 
   2013   2012 
Deferred financing costs  $393,990   $393,990 
Less: accumulated amortization   (56,431)   (5,011)
Deferred financing costs, net  $337,559   $388,979 

 

Total amortization of deferred financing costs for the year ended December 31, 2013 and 2012 was $51,420 and $5,011, respectively and is included in other general and administrative expenses.

 

12.Land Held for Development; Mortgage Receivable

 

Land held for development consisted of $110,477 as of December 31, 2013.

 

On December 18, 2013, the Company bought a defaulted note secured by a first mortgage on certain real property from Bremer Bank, National Association. The Company intends to foreclose and thereby obtain title to the land. Once title to the property has been obtained, the note will be cancelled and the land received will be reclassified to “land held for development”. The foreclosure is expected to be completed on or about April 20, 2014. The purchase price of the mortgage was $353,504 and included $340,000 of principal and $13,504 of accrued interest as of December 31, 2013.

 

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13.Debt

 

Notes payable by the Company are summarized as follows:

 

   December 31,
2013
   December 31,
2012
 
Note payable to HTS, 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 the remaining outstanding obligation. Paid in full on September 6, 2013.  $   $3,400,262 
           
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. Paid in full on April 1, 2013.       666,665 
           
Note payable to John O. Hanson dated April 8, 2011, accruing interest at 20%. The loan is payable on demand or on December 31, 2013. See "Related Party Indebtedness" below.   200,000    200,000 
           
Renewable Unsecured Subordinated Notes, see below.   9,984,826    2,013,138 
   $10,184,826   $6,280,065 

 

Notes payable by maturity are summarized as follows:

 

   December 31,
2013
   December 31,
2012
 
2013  $   $5,005,620 
2014   5,122,596     
Current maturities   5,122,596    5,005,620 
           
2014       283,500 
2015   1,266,590    350,690 
2016   772,250    193,500 
2017   549,140    281,755 
2018   2,297,250     
2019 & thereafter   177,000    165,000 
Long term debt   5,062,230    1,274,445 
Total  $10,184,826   $6,280,065 

 

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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. The Margin Agreement was amended on May 31, 2013 to reduce the uncommitted credit line to $15,000,000, the commitment fee to $25,000 per month, and the covenant with respect to net liquidating equity as defined to $1,500,000.

 

As of December 31, 2013 and 2012, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants.

 

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. As of December 31, 2012, the Company was in compliance with all covenants with respect to its note payable to Mr. Hanson. On June 28, 2013, Mr. Hanson sold the redeemable preferred units to Mr. Krieger, and consequently, as of June 30, 2013, he was no longer a related party.

 

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.

 

The Company made interest payments during the years ended December 31, 2013 and 2012 of $443,367 and $16,587, respectively. Total accrued interest on the Subordinated Notes at December 31, 2013 and 2012 was $354,094 and $50,553, respectively.

 

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As of December 31, 2013, the Company had $9,984,826 of its Subordinated Notes outstanding as follows:

 

Initial Term  Principal Amount   Weighted Average Interest Rate 
3 months  $302,752    15.27% 
6 months   186,103    8.56% 
1 year   3,634,711    12.41% 
2 years   1,176,900    12.75% 
3 years   904,440    13.70% 
4 years   435,885    14.74% 
5 years   3,167,035    15.62% 
10 years   177,000    13.66% 
Total  $9,984,826    13.72% 
           
Weighted average term   33.9 mos      

 

14.Leases

 

The Company leases office space, vehicles, and office equipment. The following table summarizes key terms of the various leases for office space.

 

Location  Expiration
Date
  Square
Footage
   Monthly
Rent
 
Lakeville, Minnesota*  12/31/2017   11,910   $12,264 
Gilbert, Arizona  1/31/2015   1,055    2,563 
Tulsa, Oklahoma*  2/28/2016   1,800    3,750 
East Windsor, New Jersey  9/30/2016   1,150    2,339 
Newtown, Pennsylvania  12/31/2017   1,711    2,250 
Total      17,626   $23,166 

____________

* See Note 17. Related Party Transactions

 

The Company has entered into several leases for vehicles and office equipment that expire between 2014 and 2018.

 

Total lease expense was $450,069 and $496,816 for the years ended December 31, 2013 and 2012, respectively.

 

Future minimum lease payments under the Company’s lease agreements are as follows:

 

Years Ended December 31,  Amount 
2014  $314,000 
2015   293,000 
2016   243,000 
2017   209,000 
2018   5,000 
Total  $1,064,000 

 

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15.Defined Contribution 401(k) Savings Plan

 

Substantially all employees are eligible to participate in the Company’s 401(k) Savings Plan (the “Savings Plan”). Employees may make pre-tax voluntary contributions to their individual accounts up to a maximum of 50% of their aggregate compensation, but not more than currently allowable Internal Revenue Service limitations. Employee participants in the Savings Plan may allocate their account balances among 14 different funds available through a third party custodian. The Savings Plan does not require the Company to match employee contributions, but does permit the Company to make discretionary contributions. No discretionary contributions have been made.

 

16.Ownership

 

On January 1, 2012, the Company redeemed 1,540 common units for $100,000.

 

Effective January 31, 2012, TCP sold 496 of its new issue redeemable preferred membership units (the “redeemable preferred”) to John O. Hanson for a purchase price of $2,745,000, paid by conversion of certain notes payable to him. The redeemable preferred incorporated a distribution of $45,750 per month, was not convertible, and had no corporate governance rights. Effective July 1, 2012, the redeemable preferred membership units issued by TCP were exchanged for redeemable preferred issued by the Company with identical rights and terms.

 

Effective December 31, 2012, Mr. Krieger purchased 525 common units held by DBJ 2001 Holdings, LLC.

 

Effective June 28, 2013, Mr. Krieger purchased all of the outstanding redeemable preferred membership units from Mr. Hanson. Concurrently with the purchase, Mr. Krieger and the Company exchanged the redeemable preferred for 496 new Series A preferred units (the “Series A preferred”) and the redeemable preferred was cancelled. The Series A preferred is not redeemable, callable, or convertible, is non-voting with respect to elections to the Company’s Board of Governors, is senior to the Company’s common equity units with respect to rights in liquidation, and is entitled to distributions out of legally available funds in the amount of $92.25 per unit per month.

 

As of December 31, 2013, the Company’s ownership is as presented below:

 

   Series A Preferred   Common 
   Units Held   Percent of Class   Units Held   Percent of Class 
At December 31, 2013                    
Timothy S. Krieger   496    100.00%    4,935    99.50% 
Summer Enterprises, LLC       0.00%    25    0.50% 
Totals   496    100.00%    4,960    100.00% 

 

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17.Related Party Transactions

 

Interest expense associated with notes payable to related parties was $31,550 and $252,942 for the years ended December 31, 2013 and 2012, respectively. See “Note 13 – Debt”.

 

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 Mr. Krieger 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 was 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. For rent, real estate taxes, and operating expenses, the Company paid Kenyon $227,200 and $207,109 for the years ended December 31, 2013 and 2012, respectively

 

Effective January 1, 2013, in connection with the purchase of David B. Johnson’s units by Mr. Krieger, the Company entered in NCA with Mr. Johnson, a current governor and former member of the Company, pursuant to which the Company is obligated to pay Mr. Johnson $500,000 in 24 equal monthly installments of $20,833 each. The total amount paid pursuant to the NCA during the year ended December 31, 2013 was $250,000.

 

On March 5, 2013, CEF entered into a 36 month lease for 1,800 square feet of office space in Tulsa, Oklahoma with the Brandon J. and Heather N. Day Revocable Trust at a monthly rent of $3,750. Mr. Day is an employee of CEF, a second-tier subsidiary of the Company. Total rent paid for the year ended December 31, 2013 was $41,250.

 

18.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, TCE may be liable for potential disgorgement of profits and 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.

 

Former Employee Litigation

 

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

 

 

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In 2013, the former employees brought applications to amend their pleadings to include certain of TCPC’s U.S. affiliates (“Twin Cities USA”). One of the former employees abandoned their application and the applications of the other two were heard on April 29 and 30, 2013. In a decision dated January 31, 2014, the Court of Queen’s Bench dismissed these applications.

 

Separately, also on January 31, 2014, the Court of Queen’s Bench ordered Twin Cities USA to post security for costs in the sum of C$75,000 together with security for judgment in the sum of C$1,376,726. On February 25, 2014, Twin Cities USA posted the security for costs with the court and filed an appeal in the Court of Appeal of Alberta seeking a stay to set aside the obligation to post security for the judgment. On March 19, 2014, the request for a stay was denied.

 

Twin Cities USA and TCPC intend to continue to vigorously defend against the allegations and claims of the former employees and file counterclaims or amended counterclaims for losses suffered and costs incurred in responding to the FERC investigation, inappropriate expenses, and related matters. Given the failure of its appeal for a stay, in order to preserve its claims and counterclaims, Twin Cities USA posted the security for the judgment on March 28, 2014.

 

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 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 was briefed before the Court of Appeals and oral argument was held on April 16, 2013.

 

In an order issued August 6, 2013, the U.S. Court of Appeals remanded to FERC for further consideration the issue of recoupment of refunds that had previously been directed by FERC.  The Court found that FERC’s orders failed to explain why refund recoupment was warranted and therefore its recoupment directive was found to be arbitrary and capricious.  In response to this remand directive, on November 22, 2013 the financial marketer appellants and interveners, including TCPH entities, filed a motion before FERC requesting that it act quickly to reconsider the refund recoupment directive found arbitrary by the Court.

 

On February 20, 2014, the FERC issued an order establishing a briefing schedule allowing parties to the proceeding to provide briefs on whether or not the recoupment orders should be reconsidered.  Although briefing on all issues relevant to the remand was invited by FERC, it also presented five specific questions, primarily relating to the effect of the recoupment orders, for the parties to address.  Initial briefs are due within 45 days of this order and reply briefs are due 30 days after the initial briefs.

 

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

 

During the period from July 2009 to July 2011, due to our participation in PJM, we were required to pay certain balancing operating reserve charges. During the same period, DC Energy, LLC and DC Energy Mid-Atlantic, LLC (collectively, “DC Energy”) inappropriately avoided such payments by reporting certain transactions as internal bilateral transactions. A FERC order dated July 12, 2013 on Docket No. EL12-8-001 denied rehearing on a complaint  by DC Energy with respect to PJM’s plan to retroactively bill them for these charges. PJM’s settlement reruns associated with these adjustments began in July 2013 and are expected to take approximately six to eight months to complete. Through February 28, 2014, the Company has received refunds totaling $611,093 from PJM ($494,771 in 2013 and $116,322 in 2014) that have been recognized as revenue. DC Energy has filed an appeal with the U.S. Court of Appeals, and should it be successful in such action, the Company may be required to return some or all of the funds received with respect to the matter, however, no reserve for such has been recorded as the Company believes the possibility of such to be remote.

 

Guarantees

 

In the ordinary course, TCPH provides guarantees for the future obligations of TCP, SUM, and CEF with respect to their participation in PJM, MISO, and ERCOT. As of December 31, 2013, such guarantees were in an unlimited amount for PJM, up to $1,500,000 for MISO, and up to $5,000,000 for ERCOT.

 

On August 12, 2013, the Company entered into a corporate guaranty in favor of Noble Americas Energy Solutions LLC (“Noble”), pursuant to which, the Company has agreed, among other things, to guarantee, up to a maximum of $1.0 million plus any costs of enforcement or collection, the prompt and complete payment of all amounts owed to Noble by TSE related to any transactions between TSE and Noble.

 

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

 

19.Segment Information

 

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

 

·Wholesale trading activities earn profits from trading financial, physical, and derivative electricity in wholesale markets regulated by the FERC and the CFTC.
·On July 1, 2012, the Company began selling electricity to residential and small commercial customers.
·On October 23, 2013, the Company formed a new entity to take advantage of certain investment opportunities in the residential real estate market.

 

Trading profits and sales are classified as “foreign” or “domestic” based on the location where the trade or sale originated. For the years ended December 31, 2013 and 2012, all such transactions were “domestic”. Furthermore, the Company has no long-lived assets in foreign jurisdictions.

 

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

 

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

 

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Information on segments for the year ended December 31, 2013 is as follows:

 

   Wholesale
Trading
   Retail
Energy Services
   Real Estate Development   Corporate, Net of Eliminations   Consolidated Total 
Year Ended
December 31, 2013
    
 
     
 
     
 
     
 
     
 
 
Wholesale trading  $25,091,983   $213,740   $   $   $25,305,723 
Retail energy services       7,479,775            7,479,775 
Revenues, net   25,091,983    7,693,515            32,785,498 
Costs of retail electricity sold       7,760,674            7,760,674 
Retail sales and marketing       493            493 
Compensation and benefits   11,041,126    194,486        2,008,229    13,243,841 
Professional fees   2,996,730    225,439        1,172,507    4,394,676 
Other general and administrative   7,314,319    868,266    13,060    (5,342,128)   2,853,517 
Trading tools and subscriptions   849,959    41,291        31,506    922,756 
Operating costs and expenses   22,202,134    9,090,649    13,060    (2,129,886)   29,175,957 
Operating income (loss)  $2,889,849   $(1,397,134)  $(13,060)  $2,129,886   $3,609,541 
Capital expenditures  $32,567   $62,308   $784,169   $180,224   $1,059,268 
                          
At December 31, 2013                         
Identifiable Assets                         
Cash - unrestricted  $1,988,248   $285,419   $   $916,828   $3,190,495 
Cash in trading accounts   8,581,233    1,903,215            10,484,448 
Accounts receivable - trade   168,952    1,146,257            1,315,209 
Note receivable       140,964            140,964 
Investment securities               256,004    256,004 
Prepaid expenses and other assets   87,499    19,728        135,255    242,482 
Total current assets   10,825,932    3,495,583        1,308,087    15,629,602 
Equipment and furniture, net   438,047    66,251            504,298 
Intangible assets, net       55,978        250,000    305,978 
Deferred financing costs, net               337,559    337,559 
Cash - restricted           320,188        320,188 
Land held for development           110,477        110,477 
Mortgage receivable           353,504        353,504 
Total assets  $11,263,979   $3,617,812   $784,169   $1,895,646   $17,561,606 
                          
Identifiable Liabilities and Equity                         
Accounts payable - trade  $619,840   $415,804   $   $   $1,035,644 
Accrued expenses       666,959        16,597    683,556 
Accrued compensation   299,439                299,439 
Accrued interest               359,758    359,758 
Notes payable               200,000    200,000 
Subordinated notes               4,922,596    4,922,596 
Obligations under non-competition agreement               250,000    250,000 
Total current liabilities   919,279    1,082,763        5,748,951    7,750,993 
Subordinated notes               5,062,230    5,062,230 
Total liabilities   919,279    1,082,763        10,811,181    12,813,223 
Investment in subsidiaries   10,006,692    2,178,435    784,169    (12,969,296)    
Series A preferred equity               2,745,000    2,745,000 
Common equity               1,302,994    1,302,994 
Accumulated other comprehensive income   338,008    356,614        5,767    700,389 
Total members' equity   10,344,700    2,535,049    784,169    (8,915,535)   4,748,383 
Total liabilities and equity  $11,263,979   $3,617,812   $784,169   $1,895,646   $17,561,606 

 

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Information on segments for the year ended December 31, 2012 is as follows:

 

   Wholesale
Trading
   Retail Energy
Services
   Real Estate Development   Corporate, Net of Eliminations   Consolidated Total 
Year Ended
December 31, 2012
                    
Revenues  $18,255,932   $817,641   $   $   $19,073,573 
Costs of retail electricity sold       763,943            763,943 
Retail sales and marketing                    
Compensation and benefits   7,201,424    93,879        1,600,148    8,895,451 
Professional fees   1,346,547    177,681        1,658,890    3,183,118 
Other general and administrative   5,044,571    538,142        (3,334,657)   2,248,056 
Trading tools and subscriptions   931,437    13,761            945,198 
Operating costs and expenses   14,523,979    1,587,406        (75,619)   16,035,766 
Operating income (loss)  $3,731,953   $(769,765)  $   $75,619   $3,037,807 
Capital expenditures  $13,908   $160,000   $   $114,820   $288,728 
                          
At December 31, 2012                         
Identifiable Assets                         
Cash  $336,909   $   $   $434,943   $771,852 
Cash in trading accounts   11,605,023    420,000            12,025,023 
Accounts receivable - trade   1,756,926    434,341            2,191,267 
Prepaid expenses and other assets   75,379            114,429    189,808 
Total current assets   13,774,237    854,341        549,372    15,177,950 
Equipment and furniture, net   82,170    6,199        482,863    571,232 
Intangible assets, net       125,326            125,326 
Deferred financing costs, net               388,979    388,979 
Total assets  $13,856,407   $985,866   $   $1,421,214   $16,263,487 
                          
Identifiable Liabilities and Equity                         
Accounts payable - trade  $780,792   $116,693   $   $571,816   $1,469,301 
Accrued expenses   189    66,565        3,624    70,378 
Accrued compensation   1,969,388            15,000    1,984,388 
Accrued interest and distributions               60,339    60,339 
Notes payable               4,266,927    4,266,927 
Subordinated notes               738,693    738,693 
Total current liabilities   2,750,369    183,258        5,656,399    8,590,026 
Subordinated notes               1,274,445    1,274,445 
Total liabilities   2,750,369    183,258        6,930,844    9,864,471 
Investment in subsidiaries   10,566,727    884,640        (11,451,367)    
Redeemable preferred equity               2,745,000    2,745,000 
Common equity               3,196,737    3,196,737 
Accumulated other comprehensive income   539,311    (82,032)           457,279 
Total members' equity   539,311    (82,032)       3,196,737    3,654,016 
Total liabilities and equity  $13,856,407   $985,866   $   $1,421,214   $16,263,487 

 

 

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