10-K

UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013

or

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Transition Period from ________ to ________

Commission File Number: 333-179460

Twin Cities Power Holdings, LLC

(Exact name of registrant as specified in its charter)

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

16233 Kenyon Avenue, Suite 210

Lakeville, Minnesota 55044

(Address of principal executive offices, zip code)

(952) 241-3103

(Registrant’s telephone number, including area code)

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

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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.

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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.

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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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o Transition 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.

o Societal benefits charges include the costs of government-mandated programs such as universal service, lifeline service, and energy efficiency programs.

o Sales 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:

o For “rate ready” utilities, the retailer posts its rates with the utility and the utility calculates the charges for inclusion on the customer’s bill.

o For “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 1^st 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.

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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 185^th 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.

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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.

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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 27^th, 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.

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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”.

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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.

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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”.

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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.

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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.

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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.

56

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.

57

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.

58

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.

59

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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20. Subsequent Events

From January 1 to March 27, 2014, the Company sold additional Subordinated Notes totaling $1,887,143 with a weighted average term of 25.3 months and bearing a weighted average interest rate of 13.60%.

On October 28, 2013, the Company entered into a Membership Interest Purchase Agreement with Gregg Ruth, Peter McCawley, and Lynn Acorda (collectively the “Sellers”) and a Management Services Agreement (the “MSA”) with RMA Services, LLC (“RMA”), a new company formed by the Sellers, pursuant to which the Company agreed to acquire all of the outstanding equity interests of Discount Energy Group, LLC (“DEG”) and purchase certain services from RMA following closing on a fixed price and performance incentive basis. DEG is licensed to provide electricity` to retail customers in Maryland, New Jersey, Ohio, and Pennsylvania. After receiving regulatory approval from FERC, the acquisition closed on January 2, 2014.

Immediately prior to closing, DEG’s assets and liabilities and equity totaled $539,289. At closing, cash and accounts receivable totaling $245,421 and accounts payable of $205,855 were transferred to RMA. At closing, TCPH paid cash to, or on behalf of, the Sellers and RMA totaling $637,000 consisting of $300,000 for the Sellers’ equity interests, $282,000 representing the net amounts on deposit with PJM and certain utilities, and $55,000 as an advance on the ultimate purchase price of certain customer accounts. Also at closing, liabilities of the Sellers and RMA totaling $596,795 were satisfied, including the $140,000 note payable to TCPH. Consequently, at closing, the Sellers received cash of $54,557.

TCPH paid total consideration for the equity of DEG of $742,283, consisting of $582,000 in cash and $162,726 in assumption of accounts payable. Of this total consideration, $281,569 was allocated to deposits, $12,300 to prepaid expenses, and $448,414 to intangible assets, which will be amortized over 24 months using the straight line method.

On January 6, 2014 TCPH received a notice from the Internal Revenue Service notifying that the Company’s 2012 return was under review by the Department.

On March 17, 2014, the Company invested $1,000,000 in a privately placed Convertible Promissory Note to be issued by Ultra Green Packaging, Inc. (“Ultra Green”) once the offering minimum of $2,000,000 has been achieved. The notes will mature five years from the date of issuance and bear a fixed interest rate of 10% per annum. Interest will accrue until December 31, 2014, at which time all accrued and unpaid interest will become due and payable. Thereafter, interest will be due and payable on a monthly basis. At the option of the holders, the notes will be convertible prior to or at maturity in shares of Ultra Green’s Series B Preferred Stock.

On March 25, 2014, the Company’s note payable to John O. Hanson was paid in full.

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

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Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A - Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) that are designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is: (a) recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and (b) accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Our management does not expect that our disclosure controls or our internal control over financial reporting will prevent or detect all errors and all fraud. 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. We cannot ensure that any design will succeed in achieving its stated goals under all potential future conditions.

In connection with the filing of this Form 10-K, management evaluated, under the supervision and with the participation of the Company’s Chief Executive Officer, Timothy S. Krieger, and Chief Financial Officer, Wiley H Sharp, III, the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of December 31, 2013. Based upon that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2013.

Changes in Internal Control over Financial Reporting

During the three months ended December 31, 2013, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

The Company’s internal control report is included in this report in Item 8, under the heading “Management’s Report on Internal Controls over Financial Reporting.”

Item 9B – Other Information

None.

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Part III

Item 10 – Directors, Executive Officers, and Corporate Governance

Governors and Executive Officers

Pursuant to the terms of our Member Control Agreement, our affairs are managed by our board of governors (the “Board”). Governors hold office until the election and qualification of their successors and generally serve the same role as directors do for corporations. Officers, also referred to as managers under our Member Control Agreement, are elected by the Board and serve at their direction.

The following table lists our executive officers and governors:

Name	Age	Position
Timothy S. Krieger	48	Chairman of the Board of Governors, Chief Executive Officer, and President
Wiley H. Sharp III (1)	57	Vice President - Finance and Chief Financial Officer
Keith W. Sperbeck	42	Vice President – Operations and Secretary
Stephanie E. Staska (1)	31	Vice President – Risk Management and Chief Risk Officer
David B. Johnson (1, 3)	63	Governor
Mark A. Cohn (2, 3)	57	Governor
William M. Goblirsch (2, 3)	70	Governor

____________

(1) Member of the Risk Management Committee.

(2) Member of the Audit Committee.

(3) Member of the Compensation Committee.

Timothy S. Krieger has served as the Chairman of the Board, Chief Executive Officer and President of the Company and its predecessors since their dates of inception. Until January 1, 2010, Mr. Krieger was a governor, co-founder, and the Secretary and Treasurer of Fairway Dairy & Ingredients, LLC (“FDI”), a buyer and seller of dairy commodities, and FDI’s affiliates. Mr. Krieger graduated from Iowa State University in 1989 with a BBA in marketing. The principal qualifications that led to Mr. Krieger’s selection as a governor include his extensive experience with the Company and its businesses.

Wiley H. Sharp III was appointed Vice President of Finance and Chief Financial Officer of the Company on March 6, 2012. Mr. Sharp is also a co-founder and Partner of Altus Financial Group LLC, a boutique investment banking firm specializing in the institutional placement of senior debt facilities, junior capital, and project financing, a position he has held since 2005. From May to October 2011, Mr. Sharp also served as Vice President - Finance for Christopher & Banks Corporation, a publicly traded retailer of women’s clothing. Mr. Sharp graduated from Tulane University in 1979 with a BS in management. He currently holds Series 79 (Investment Banking Representative), Series 7 (General Securities Representative), and Series 63 (Uniform State Securities Law) FINRA licenses.

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Keith W. Sperbeck was appointed Vice President of Operations and Secretary of the Company on February 1, 2012, and has been employed by TCP since April 2009 as Vice President of Operations. Mr. Sperbeck was also elected as the Treasurer and Secretary for all of our subsidiaries on February 1, 2012. From February 2004 to April 2009, he was employed by Citizens Bank Minnesota as a Vice President with responsibility for commercial lending, branch operations, and employee development.

Stephanie E. Staska was appointed Vice President of Risk Management and Chief Risk Officer of TCPH on February 1, 2012, and has been employed by TCP since August 2008 in the same role. From September 2004 to August 2008, she was employed by Cargill, Inc., a global commodity trading concern and the 2^nd largest private company in the United States, serving most recently as a Senior Risk Analyst within the trade and structured finance and corporate treasury functions. Ms. Staska attended the Carlson School of Management at the University of Minnesota and received her MBA in December 2007 and her BSB in actuarial science in May 2003.

Mark A. Cohn was elected a Governor on January 4, 2013. Mr. Cohn is currently the Chairman and Chief Executive Officer of Third Season, LLC, a company founded as an incubator of micro-consumer marketing companies, a position he has held since founding the company in 2003. During 2010, he was also the Managing Director and Chief Executive Officer of Dorado Ocean Resources Limited, a deep ocean mining company. From 2003 to 2009, he served as Chief Executive Officer of Second Act, an e-commerce company focused on the resale of consumer electronics. Mr. Cohn served as Chairman, President and Chief Executive Officer of Intelefilm Corporation from October 2001 to August 2002. From its inception in 1986 until February 2001, Mr. Cohn was founder and Chief Executive Officer of Damark International, Inc., a consumer catalog company. During that time, Damark grew to become one of the nation’s largest consumer marketing companies with revenues of $600 million. At its peak, Damark had a market capitalization of over $500 million and employed 2,000 people in three states. Mr. Cohn currently serves as a member of the Board of Directors of Christopher and Banks Corporation, a specialty retailer of women’s clothing (NYSE-CBK) with over 650 stores in the US. In 2012, the National Association of Corporate Directors named him a Governance Fellow. The principal qualifications that led to Mr. Cohn’s selection as a Governor include his extensive experience with publicly reporting companies, and in direct marketing and finance.

William M. Goblirsch was elected a Governor on May 4, 2012. Since January 1, 2013, Mr. Goblirsch has been employed as Chief Financial Officer of Tzfat Spirits of Israel, LLC and also serves as a member on their Board of Governors. Prior to such time, he served as an independent financial consultant. Mr. Goblirsch is a certified public accountant (inactive license) who started his career forty years ago with Arthur Andersen. Mr. Goblirsch has been, at various times, financial consultant to the creditors’ committee, EVP-CFO, and board member of Stockwalk Group Inc. He has also served as CFO for a blender, packager and distributor of oil products and lubricants; a cellular air time reseller; and a shopping mall franchisor of dental centers. The principal qualifications that led to Mr. Goblirsch’s selection as a Governor include his extensive financial background.

David B. Johnson has served as a Governor of the Company since December 21, 2011. Mr. Johnson is currently Chief Executive Officer of Cedar Point Capital, LLC, a private company that raises capital for early stage companies, a position he has held since May 2007. Prior to forming Cedar Point, he served as a Managing Director of Private Placements at Stifel, Nicolaus & Company, an investment banking firm, beginning in December 2006 when Stifel purchased Miller Johnson Steichen Kinnard, Inc., an investment banking firm specializing in high-tech, medical device and other start-up and growth companies, of which Mr. Johnson was a founder, and lastly served as Chief Executive Officer. Mr. Johnson graduated from Augsburg College in Minneapolis, MN in 1973 with a BS in business. The principal qualifications that led to Mr. Johnson’s selection as a Governor include his experience with growth companies and companies that undergo initial public offerings.

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Board Composition, Election of Governors, and Committees

Our Board currently consists of four members. All governors serve for an indefinite term until the election and qualification of their successors. At least two of our governors are independent as defined by the applicable rules of The Nasdaq Stock Market. While we have not applied for listing on Nasdaq or any other securities exchange or market, we have chosen to apply Nasdaq’s independence standards in making our determination of independence.

Our Board has established a Risk Management Committee, an Audit Committee, and a Compensation Committee.

Risk Management Committee

The members of our Risk Management Committee (“RMC”) are David Johnson, who serves as chair, Stephanie Staska, and Wiley Sharp III. The RMC is responsible for developing and ensuring compliance with risk policies for measurement and oversight of risk. The RMC reports to the Board.

The RMC is responsible for setting risk policies and standards for risk measurement and ensuring that risk policies, strategies, procedures, and controls are fully documented and communicated. It also oversees and reviews the risk management process and infrastructure and is responsible for keeping the Board and the Audit Committee informed of all risk management activities.

The RMC also has the following responsibilities:

· Guide management in risk policy development and adopt, subject to Board approval, the risk policies, restrictions, and limitations of the Company and its traders;

· Guide development in risk appetite, limits setting, and exception protocols;

· Develop and gain consensus of risk management policy, strategy, appetite, and roll-out plans;

· Develop and guide in the implementation of risk management and measurement approaches;

· Approve resource requirements;

· Evaluate risk responsiveness of the organization’s risk events;

· Communicate risk management progress and successes to the Board;

· Monitor and fine-tune risk management processes as required;

· Identify data and information system requirements to support risk management function;

· Contemporaneously communicate to the Board any risk profile changes;

· Monitor corporate compliance with risk limits and policies and report to Board on compliance; and

· Identify gaps in existing policies, systems, and procedures.

Audit Committee

Our Audit Committee consists of William Goblirsch, who serves as chair, and Mark Cohn, both of whom are independent. The Audit Committee assists our Board in its oversight of the integrity of our consolidated financial statements, our independent registered public accounting firm’s qualifications and independence, and the performance of our independent registered public accounting firm.

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The Audit Committee’s responsibilities include:

· Appointing, approving the compensation of, and assessing the independence of, our independent registered public accounting firm;

· Overseeing the work of our independent registered public accounting firm, including the receipt and consideration of reports;

· Reviewing and discussing with management and our independent registered public accounting firm our annual and quarterly consolidated financial statements and related disclosures;

· Monitoring our internal control over financial reporting, disclosure controls and procedures, and code of business conduct and ethics;

· Establishing procedures for the receipt and retention of accounting-related complaints and concerns;

· Meeting independently with our independent registered public accounting firm and management; and

· Preparing the Audit Committee report required by SEC rules.

All audit and non-audit services, other than de minimus non-audit services to be provided by our independent registered public accounting firm must be approved in advance by our Audit Committee.

Compensation Committee

Our Compensation Committee consists of Mark Cohn, who serves as chair, David Johnson, and William Goblirsch, and assists our Board in the discharge of its responsibilities relating to the compensation of our executive officers.

The Compensation Committee’s responsibilities include:

· Reviewing, approving, or making recommendation to the Board with respect to our chief executive officer’s compensation;

· Evaluating the performance of our executive officers and reviewing, approving, or making recommendations to the Board with respect to the compensation of our executive officers;

· Overseeing and administering, and making recommendations to the Board with respect to any cash and equity incentive plans that the Board may adopt; and

· Reviewing and making recommendations to the Board with respect to governor compensation.

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Item 11 - Executive Compensation

Summary Compensation Table

The following table sets forth the compensation paid to our Principal Executive Officer (“PEO”) and named executive officers during the years ended December 31, 2013 and 2012:

Name and Principal Position	Year	Salary ($)		Bonus ($)		Other Incentive Compensation ($) (1)		All Other Compensation ($) (2)		Total ($)
Timothy S. Krieger	2013		600,000		–		–		17,320		617,320
Chairman of the Board, Chief Executive Officer, and President, PEO	2012		600,000		14,500		–		15,988		630,488
Wiley H. Sharp III	2013		173,500		25,000		–		4,790		203,290
Vice President - Finance and Chief Financial Officer (3)	2012		134,000		–		–		–		134,000
Keith W. Sperbeck	2013		180,000		–		–		23,554		203,554
Vice President – Operations and Secretary	2012		180,000		–		–		21,540		201,540
Stephanie E. Staska	2013		150,000		45,000		–		22,234		217,234
Vice President – Chief Risk Officer	2012		136,000		45,000		–		19,325		200,325

____________

(1) The Company does not have an incentive stock plan, non-equity incentive plan, or non-qualified deferred compensation plan, and consequently, there were no stock awards, option awards, non-equity incentive plan compensation, or non-qualified deferred compensation earnings.

(2) Other compensation consists of health care premiums paid on behalf of the employee and, in the case of Ms. Staska, tuition reimbursement.

(3) Mr. Sharp was hired on March 8, 2012.

Outstanding Equity Awards

The Company does not have an incentive stock plan, non-equity incentive plan, or non-qualified deferred compensation plan, and consequently, there were no stock awards, option awards, non-equity incentive plan compensation, or non-qualified deferred compensation earnings for any of our named executive officers outstanding as of the end of our last completed fiscal year.

Governor Compensation

On July 18, 2012, the Board resolved to provide compensation to Board and Committee members as follows:

· Each non-employee governor attending board meetings in person - $5,000.

· Each non-employee governor attending a committee meeting in person and serving as chair - $1,500.

· Each non-employee governor attending a committee meeting in person - $1,000.

· Any Board or Committee meeting attended telephonically reduces fees by one-half.

The Company does not have an incentive stock plan, non-equity incentive plan, or non-qualified deferred compensation plan, or provide retirement benefits for governors.

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The amount of compensation each governor received in 2013 is shown in the table below:

Name and Committee Assignments	Fees Earned or Paid in Cash ($) (1)		Stock Awards ($) (2)		Total ($)
Mark A. Cohn   Chairman, Compensation Committee   Member, Audit Committee		24,000		–		24,000
William M. Goblirsch   Chairman, Audit Committee   Member, Compensation Committee		24,750		–		24,750
David B. Johnson   Chairman, Risk Management Committee		24,750		–		24,750

___________

(1) Represents cash payments of meeting fees and additional payments for service as committee chairs or members.

(2) The Company does not have an incentive stock plan, non-equity incentive plan, or non-qualified deferred compensation plan, and consequently, there were no stock awards, option awards, non-equity incentive plan compensation, or non-qualified deferred compensation earnings.

Retirement Plans

Except as described below, we currently have no plans that provide for the payment of retirement benefits, or benefits that will be paid primarily following retirement, including but not limited to tax-qualified defined benefit plans, supplemental executive retirement plans, tax-qualified defined contribution plans, and nonqualified defined contribution plans.

The Company maintains a 401(k) plan that is tax-qualified for its employees, including its executive officers. The plan does not offer employer matching, however, it does offer a discretionary employer contribution at year-end. No discretionary contributions have been made.

Potential Payments Upon Termination or Change-in-Control

Except as described below under “Employment Agreements”, we currently have no contract, agreement, plan or arrangement, whether written or unwritten, that provides for payments to a named executive officer at, following, or in connection with any termination, including without limitation resignation, severance, retirement, or a constructive termination of a named executive officer, or a change in control of the Registrant or a change in the named executive officer’s responsibilities, with respect to each named executive officer.

Employment Agreements

The following are summaries of our employment and consulting agreements with our named executive officers:

Timothy S. Krieger: On January 1, 2012, TCPH entered into an employment agreement with Mr. Krieger, which was amended effective January 1, 2014. Mr. Krieger is the beneficial owner of 100% of the Company’s outstanding equity. Pursuant to the amended employment agreement, as of January 1, 2014. Mr. Krieger no longer receives a salary from the Company but receives distributions on both his preferred and common units. In the first three months of 2014, Mr. Krieger received required distributions on his preferred units of $45,756 per month. He also received additional distributions totaling $1.4 million. If Mr. Krieger’s employment is terminated for reasons other than cause, he will receive no severance pay. If Mr. Krieger’s employment is terminated for any reason other than non-renewal, he is subject to a non-compete agreement for a period of six months. If his employment is not renewed by the Company at the end of the original one-year term or any subsequent renewal term, Mr. Krieger will not be subject to a non-compete and he will not receive any severance pay.

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Wiley H. Sharp III: On March 8, 2012, we entered into a Consultant and Professional Services Agreement with Wiley H. Sharp III pursuant to which he served as Vice President – Finance and Chief Financial Officer for TCPH. We paid Mr. Sharp $11,000 per month for his services; subject to an increase to $15,000 per month should the Acquisition Advisory Agreement dated January 5, 2012 between the Company and Altus Financial Group, LLC, of which Mr. Sharp is a 50% partner, be terminated. The Acquisition Advisory Agreement was terminated by mutual consent on July 1, 2012 and effective March 1, 2013. The Company and Mr. Sharp extended the Consultant and Professional Services Agreement until May 31, 2013. Effective June 15, 2013, the independent contractor arrangement between TCPH and Mr. Sharp was terminated by mutual consent and on June 16, 2013, the parties entered into an employment agreement pursuant to which Mr. Sharp serves as Vice President – Finance and Chief Financial Officer for TCPH. Mr. Sharp currently receives an annual salary of $168,000 and is eligible for a discretionary bonus based on Company performance. If Mr. Sharp’s employment is terminated for reasons other than cause, he will receive three months of severance pay.

Keith W. Sperbeck: On February 1, 2012, TCPH assumed the employment agreement entered into between TCP and Mr. Sperbeck effective April 13, 2008, as amended on May 29, 2010. Mr. Sperbeck currently receives an annual salary of $180,000. The agreement also provides that Mr. Sperbeck will receive $100,000 as compensation if he obtains equity or debt financing for the Company on terms and conditions that are acceptable to the Company’s CEO in his sole opinion. If Mr. Sperbeck’s employment is terminated for reasons other than cause, he will receive twelve months of severance pay. If Mr. Sperbeck’s employment is terminated for any reason, he is subject to a non-compete agreement for a period of twelve months. While not stated in his employment agreement, Mr. Sperbeck is eligible for a discretionary bonus based on Company performance.

Stephanie E. Staska: On February 1, 2012, TCPH assumed the employment agreement entered into between TCP and Ms. Staska effective August 18, 2008, as amended on January 1, 2012 and 2013, and March 1, 2014. Under the employment agreement, as amended, Ms. Staska currently receives an annual salary of $180,000. She is also eligible for a discretionary bonus based on Company performance. If Ms. Staska’s employment is terminated for reasons other than cause, she will receive three months of salary as severance pay.

Compensation Policies and Practices as They Relate to Risk Management

We believe that risks arising from our compensation policies and practices for our employees, and the respective policies and practices for our subsidiaries, are not reasonably likely to have a material adverse effect on us. In addition, our Board believes that the mix and design of the elements of executive compensation do not encourage management to assume excessive risks.

Our energy traders are compensated largely through bonuses based on the success of their trading activities. They must restore any losses, even losses from prior fiscal quarters, before they will be eligible for any bonuses. While such a policy does create an incentive to engage in more risky trading activities designed to recoup losses, given the trading restrictions we have in place, which include position limits and VaR limits, we do not believe that our compensation practices encourage excessive risk taking. See “Business – Wholesale Trading - Market Risk Management” and “Quantitative and Qualitative Disclosures About Market Risk”.

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Indemnification of Governors and Executive Officers and Limitations of Liability

Under our Member Control Agreement, as amended (the “MCA”), we indemnify our governors and officers against liabilities they may incur in such capacities including liabilities under the Securities Act of 1933, as amended (the “Securities Act”). The MCA provides for the indemnification, to the fullest extent permitted by the Securities Act and Minnesota law, as amended from time to time, of officers, governors, employees, and agents of the Company. We may, prior to the final disposition of any proceeding, pay expenses incurred by an officer or governor upon receipt of an undertaking by or on behalf of that governor or officer to repay those amounts if it should be determined ultimately that he or she is not entitled to be indemnified under the MCA or otherwise. We shall indemnify any officer, governor, employee or agent upon a determination that such individual has met the applicable standards of conduct specified in the MCA. In the case of an officer or governor, the determination shall be made (1) by the Board by a majority vote of a quorum consisting of governors who are not parties to such action, suit, or proceeding or (2) if such a quorum is not obtainable, or, even if obtainable, if a quorum of disinterested governors so directs, by independent legal counsel in a written opinion, or (3) by a majority vote of disinterested members.

The MCA provides that each governor will continue to be subject to liability for any act or omission that constitutes fraud, willful misconduct, bad faith, gross negligence, or a breach of the MCA.

We have entered into indemnification agreements with our officers and governors. These agreements provide each such individual with indemnification retroactively for actions taken in his or her role as an officer or governor to the Company.

We have been advised that in the opinion of the Securities and Exchange Commission, insofar as indemnification for liabilities arising under the Securities Act may be permitted to our governors, officers, and controlling persons pursuant to the foregoing provisions, or otherwise, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. In the event a claim for indemnification against such liabilities (other than our payment of expenses incurred or paid by its governor, officer, or controlling person in the successful defense of any action, suit or proceeding) is asserted by such governor, officer, or controlling person in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

At present, there is no pending litigation or proceeding involving any of our governors, officers, or employees in which indemnification is sought, nor are we aware of any threatened litigation that may result in claims for indemnification.

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Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth information concerning beneficial ownership of our common units as of March 28, 2013 for: (a) each director; (b) the executive officers as set forth in the Summary Compensation Table; and (c) the directors and current executive officers as a group. Unless otherwise indicated, each person has sole investment and voting power (or shares such powers with his or her spouse) with respect to the shares set forth in the following table.

Name and Principal Position of Beneficial Owner	Common Units		Percent of Class
Timothy S. Krieger   Chairman of the Board, Chief Executive Officer, and President (1)		4,960		100.00%
David B. Johnson   Governor		–		0.00%
William M. Goblirsch   Governor		–		0.00%
Mark A. Cohn   Governor		–		0.00%
Wiley H. Sharp III   Vice President - Finance and Chief Financial Officer		–		0.00%
Keith W. Sperbeck   Vice President - Operations and Secretary		–		0.00%
Stephanie E. Staska   Vice President – Risk Management and Chief Risk Officer		–		0.00%
All governors & executive officers as a group   (7 persons)		4,960		100.00%

____________

1 - Includes 25 common units held by Summer Enterprises, LLC, a company controlled by Mr. Krieger.

Item 13 – Certain Relationships, Related Transactions, and Director Independence

The following is a description of certain transactions and relationships between us and our governors, officers, and other affiliates during 2013. Other than in connection with the transactions described below, we have not been a party to, and we have no plans to be a party to, any transaction or series of similar transactions in which the amount involved exceeded or will exceed $120,000 and in which any governor, executive officer, holder of more than 5% of our units of limited liability company interest, or any member of the immediate family of any of the foregoing, had or will have a direct or indirect material interest.

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Joinder Agreement with Former Members

Effective January 1, 2010, Tom Beatty and John Beatty (collectively, the “Beattys”) transferred to Timothy Krieger all of the Beattys’ financial rights to 1,870 membership units in each of TCP, TCE, and CP pursuant to the Assignment of Financial Rights Agreements (the “Assignments”). Under the Assignments, the Beattys agreed to transfer the corresponding governance rights to such membership units to Mr. Krieger upon the happening of certain events. In order to induce the Beattys to transfer the governance rights to Mr. Krieger and thereby allow Mr. Krieger to transfer the membership interests in TCP, TCE, and CP unencumbered to TCPH on December 31, 2011, the effective date of the Reorganization described above in “Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements, Note 1 – Organization”, TCPH, TCP, TCE, and CP entered into a Joinder Agreement on December 23, 2011 with the Beattys and Mr. Krieger. Pursuant to the Joinder Agreement, the Company assumed all of the obligations, including certain contingent payment obligations owed by TCP, TCE, CP, and Mr. Krieger to the Beattys under the Assignments. Specifically, we agreed that in the event of a sale, lease, license, or other transfer of all or any significant portion of our assets, or the sale, issuance, redemption, or exchange of more than 25% of the equity in us or our subsidiaries, whether by unit sale, redemption, exchange, merger, consolidation, reorganization, or similar type transaction, upon the closing of such a transaction, we would pay the Beattys an amount equal to 100% of the proceeds from such transaction that would otherwise be received or allocated to the Beattys if they had continued to own 1,870 membership units. This payment is decreased by one-third annually on each of January 1, 2012 and 2013 and does not apply to any transaction entered into on or after January 1, 2015.

Real Estate Leases

The Company is subject to a lease with Kenyon Holdings, LLC (“Kenyon”) for the office space in Lakeville, Minnesota. Kenyon, which is owned by Timothy S. Krieger, CEO, and Keith W. Sperbeck, Vice President – Operations, purchased that building on June 23, 2011. Effective January 1, 2013, the Company entered into a new lease with Kenyon at what it believes to be market rates. Under the lease, which is for 11,910 square feet, the Company is required to pay base rent of $12,632, as well as estimated real estate taxes and operating expenses for 2014 of $7,959 for an approximate total of $20,591 per month.

Acquisition Advisory Agreement

On January 5, 2012, we entered into an Acquisition Advisory Agreement with Altus Financial Group LLC, of which Wiley H. Sharp III, our Vice President – Finance and CFO, is a 50% partner. Pursuant to this agreement, Altus Financial Group LLC agreed to provide us with certain services in connection with acquisitions within the retail electricity industry. This agreement was amended effective March 6, 2012, in connection with Mr. Sharp joining the Company and was terminated by mutual consent effective July 1, 2012.

Item 14 – Principal Accountants’ Fees and Services

Baker Tilly Virchow Krause, LLP (“BTVK”) is our principal independent registered public accountant and has audited the Company’s consolidated financial statements since 2009. Audit services provided by BTVK in 2013 included the audit of consolidated financial statements of the Company, reviews of interim consolidated financial information, and consultation on matters related to accounting and financial reporting.

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Audit and Non-Audit Fees

The following table presents fees for professional services performed by BTVK for the audit of the Company’s annual financial statements for 2013 and 2012, the review of the Company’s interim consolidated financial statements for the first, second, and third quarters of 2013 and 2012, and for audit-related, tax, and other services performed in 2013 and 2012.

	Years ended December 31,
	2013		2012
Audit fees (1)	$	124,351	$	127,317
Audit-related fees (2)		–		21,070
Tax fees (3)		46,190		94,364
Other fees (4)		5,300		2,500
Total	$	175,841	$	245,251

____________

1 -	“Audit fees” includes the annual audits of the Company’s consolidated financial statements, reviews of interim consolidated financial statements included on Form 10-Q for the first, second and third quarters of 2013, consultation on matters related to financial reporting, and consents for securities offerings.
2 -	“Audit-related fees” includes fees billed for assurance and related services that are reasonably related to the performance of audits or reviews of financial statements and are not reported under "Audit fees", such as consultation for Form S-1 registration.
3 -	“Tax fees” include fees billed for professional services rendered for tax returns ($38,915 in 2013 and $41,172 in 2012) and tax advice and planning ($7,275 in 2013 and $50,465 in 2012).
4 -	“Other fees” includes fees billed for services provided other than the services described above such as miscellaneous research projects and consultation in regard to the cessation of Canadian operations.

Audit Committee Pre-Approval Policies

For fiscal years beginning after January 1, 2013, our Audit Committee has adopted pre-approval policies and procedures pursuant to which audit, audit-related, tax services, and all permissible non-audit services, are pre-approved by category of service. The fees are budgeted, and actual fees versus the budgeted amounts are monitored throughout the year.

During the year, circumstances may arise when it may become necessary to engage the independent auditor for additional services not contemplated in the original pre-approval. In those instances, we will obtain the specific pre-approval of the Audit Committee before engaging the independent auditor. Our policy requires the Audit Committee to be informed of each service, and the policies do not include any delegation of the Audit Committee’s responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

During 2013, the appointment of Baker Tilly Virchow Krause as Independent Registered Public Accountants was approved by the Board.

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Part IV

Item 15 – Exhibits, Financial Statement Schedules

Exhibit Number	Description
2.1	Agreement and Plan of Reorganization, dated November 14, 2011, as amended December 20, 2011 (incorporated by reference to Exhibit 2.1 to the Registrant’s Form S-1 filed February 10, 2012)
3.1(i)	Articles of Organization (incorporated by reference to Exhibit 3.1 to the Registrant’s Form S-1 filed February 10, 2012)
3.1(ii)	Bylaws (incorporated by reference to Exhibit 3.1 to the Registrant’s Form S-1 filed February 10, 2012)
3.2	Amended and Restated Member Control Agreement (incorporated by reference Exhibit 3.1 to the Registrant’s Form 10-Q filed November 14, 2012)
3.3	Buy/Sell Agreement (incorporated by reference to Exhibit 3.3 to the Registrant’s Form S-1 filed February 10, 2012)
3.4	First Amendment to Amended and Restated Member Control Agreement of Twin Cities Power Holdings, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed August 16, 2013)
3.5	Second Amendment to Amended and Restated Member Control Agreement of Twin Cities Power Holdings, LLC (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed September 11, 2013)
4.1	Form of Indenture (incorporated by reference 4.1 to the Registrant’s Form S-1/A filed March 30, 2012)
4.2	Form of Notes (included as Exhibit A to the Indenture filed as Exhibit 4.1 to the Registrant’s Form S-1/A filed March 30, 2012)
4.3	Form of Note Confirmation (incorporated by reference to Exhibit 4.3 to the Registrant’s Form S-1/A filed May 7, 2012)
4.4(i)	Form of Subscription Agreement (incorporated by reference to Exhibit 4.3 to the Registrant’s Form S-1/A filed May 7, 2012)
4.4(ii)	Form of Subscription Agreement for investors from states with suitability standards (incorporated by reference to Exhibit 4.3 to the Registrant’s Form S-1/A filed May 7, 2012)
4.5	Paying Agent Agreement (incorporated by reference to Exhibit 4.1 to the Registrant’s Form S-1/A filed March 30, 2012)
10.1	Employment Agreement between the Company and Timothy Krieger (*) (incorporated by reference to Exhibit 10.1 to the Registrant’s Form S-1 filed February 10, 2012)
10.2	Employment Agreement between the Company and Keith Sperbeck (*) (incorporated by reference to Exhibit 10.2 to the Registrant’s Form S-1 filed February 10, 2012)

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Exhibit Number	Description
10.3	Employment Agreement between the Company and Stephanie Staska (*) (incorporated by reference to Exhibit 10.3 to the Registrant’s Form S-1 filed February 10, 2012)
10.4	Second Amendment to Employment Agreement dated December 31, 2012 between Twin Cities Power Holdings, LLC and Stephanie Staska (*) (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed March 18, 2013)
10.5	Membership Unit Purchase Agreement between the Company and Michael Tufte (incorporated by reference to Exhibit 10.4 to the Registrant’s Form S-1/A filed March 30, 2012)
10.6	Form of Indemnification Agreement between the Company and each of Timothy Krieger, David Johnson, Wiley H. Sharp III, Keith Sperbeck, Stephanie Staska, Mark Cohn, and William M. Goblirsch (incorporated by reference to Exhibit 10.5 to the Registrant’s Form S-1 filed February 10, 2012)
10.7	Outsourcing Agreement, dated May 9, 2012, between the Company and Redwater LLC (incorporated by reference to Exhibit 10.6 to the Registrant’s Form S-1/A filed May 7, 2012)
10.8	Office Lease, dated January 1, 2013 between Twin Cities Power Holdings, LLC and Kenyon Holdings, LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed March 18, 2013)
10.9	Promissory Note, dated October 1, 2011, payable to Robert O. Schachter, HTS Capital, LLC and Clearwaters Capital, LLC (incorporated by reference to Exhibit 10.8 to the Registrant’s Form S-1 filed February 10, 2012)
10.10	Promissory Note, dated January 1, 2012, payable to Michael Tufte (incorporated by reference to Exhibit 10.9 to the Registrant’s Form S-1 filed February 10, 2012)
10.11	Loan Agreement, dated September 1, 2006, payable to John Hanson (incorporated by reference to Exhibit 10.10 to the Registrant’s Form S-1 filed February 10, 2012)
10.12	Loan Agreement, dated April 1, 2008, payable to John Hanson (incorporated by reference to Exhibit 10.11 to the Registrant’s Form S-1 filed February 10, 2012)
10.13	Note Payable, dated April 8, 2011, payable to John Hanson (incorporated by reference to Exhibit 10.12 to the Registrant’s Form S-1 filed February 10, 2012)
10.14	Promissory Note Extension dated on or around December 10, 2012 between John O. Hanson and Twin Cities Power, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed March 18, 2013)
10.15	Loan Agreement, dated July 16, 2009, payable to Patrick Sunseri (incorporated by reference to Exhibit 10.13 to the Registrant’s Form S-1 filed February 10, 2012)

96

Exhibit Number	Description
10.16	Acquisition Advisory Agreement, dated January 5, 2012, between Twin Cities Power, LLC and Altus Financial Group LLC (incorporated by reference to Exhibit 10.14 to the Registrant’s Form S-1 filed February 10, 2012)
10.17	Joinder Agreement, dated December 23, 2011, and underlying Assignment of Financial Rights Agreements, each dated January 1, 2010 (incorporated by reference to Exhibit 10.15 to the Registrant’s Form S-1 filed February 10, 2012)
10.18	Form of Trader Employment Agreement (incorporated by reference to Exhibit 10.16 to the Registrant’s Form S-1 filed February 10, 2012)
10.19	Corporate Guaranty, dated December 29, 2011, by the Company in favor of Midwest Independent Transmission System Operator, Inc. (incorporated by reference to Exhibit 10.17 to the Registrant’s Form S-1 filed February 10, 2012)
10.20	Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Summit Energy, LLC) (incorporated by reference to Exhibit 10.18 to the Registrant’s Form S-1 filed February 10, 2012)
10.21	Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Twin Cities Energy, LLC) (incorporated by reference to Exhibit 10.19 to the Registrant’s Form S-1 filed February 10, 2012)
10.22	Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for TC Energy Trading, LLC) (incorporated by reference to Exhibit 10.20 to the Registrant’s Form S-1 filed February 10, 2012)
10.23	Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Twin Cities Power, LLC) (incorporated by reference to Exhibit 10.21 to the Registrant’s Form S-1 filed February 10, 2012)
10.24	Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Cygnus Energy Futures, LLC) (incorporated by reference to Exhibit 10.22 to the Registrant’s Form S-1 filed February 10, 2012)
10.25	Consultant and Professional Services Agreement, dated March 8, 2012, between TCPH and Wiley H. Sharp III (*) (incorporated by reference to Exhibit 10.23 to the Registrant’s Form S-1/A filed March 30, 2012)
10.26	First Amendment to Consultant and Professional Services Agreement effective March 1, 2013 between Twin Cities Power Holdings, LLC and Wiley H. Sharp III (*) (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed March 18, 2013)
10.27	Futures Risk-Based Margin Finance Agreement, dated January 2, 2012, between CEF and ABN AMRO (incorporated by reference to Exhibit 10.24 to the Registrant’s Form S-1/A filed March 30, 2012)
10.28	Addendum to Promissory Note payable to Robert O. Schachter, HTS Capital, LLC and Clearwaters Capital, LLC (incorporated by reference to Exhibit 10.25 to the Registrant’s Form S-1/A filed March 30, 2012)
10.29	Membership Unit Purchase Agreement, dated March 28, 2012, between Twin Cities Power, LLC and John Hanson (incorporated by reference to Exhibit 10.26 to the Registrant’s Form S-1/A filed March 30, 2012)

97

Exhibit Number	Description
10.30	Assignment of Membership Unit Purchase Agreement, effective July 1, 2012 (incorporated by reference Exhibit 10.1 to the Registrant’s Form 10-Q filed November 14, 2012)
10.31	First Amendment to Loan Documents between Patrick C. Sunseri and Twin Cities Power, LLC dated as of May 14, 2012 (incorporated by reference Exhibit 10.1 to the Registrant’s Form 10-Q filed June 25, 2012)
10.32	Agreement dated as of May 22, 2012 between Katmando Holdings Inc. and Twin Cities Power Holdings, LLC (incorporated by reference Exhibit 10.2 to the Registrant’s Form 10-Q filed June 25, 2012)
10.33	Assignment of Membership Unit Purchase Agreement, effective July 1, 2012 (incorporated by reference Exhibit 10.1 to the Registrant’s Form 10-Q filed November 14, 2012)
10.34	Market Participant Guarantee Agreement (the “Guarantee”) with Electric Reliability Council of Texas, Inc. dated December 3, 2012 (incorporated by reference to Exhibit 10.34 to the Registrant’s Form 10-K filed March 29, 2013)
10.35	Office Lease dated March 1, 2013 between Cygnus Energy Futures, LLC and the Brandon J. and Heather N. Day Revocable Trust (incorporated by reference to Exhibit 10.35 to the Registrant’s Form 10-K filed March 29, 2013)
10.36	Corporate Guaranty by Twin Cities Power Holdings, LLC in favor of PJM Interconnection dated April 16, 2013 (incorporated by reference  to the Registrant’s Form 8-K filed April 16, 2013)
10.37	Promissory Note Extension dated June 13, 2013 between John O. Hanson and Twin Cities Power, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed June 20, 2013)
10.38	Employment Agreement dated June 16, 2013 between Twin Cities Power Holdings, LLC and Wiley H. Sharp III (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed June 20, 2013)
10.39	Corporate Guaranty by Twin Cities Power Holdings, LLC in favor of Midcontinent Independent System Operator, Inc. dated August 22, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed August 26, 2013)
10.40	Corporate Guaranty of Twin Cities Power Holdings, LLC in favor of Noble Americas Energy Solutions LLC, dated August 12, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed September 11, 2013)
10.41	Membership Interest Purchase Agreement dated October 28, 2013 between Twin Cities Power Holdings, LLC, Gregg Ruth, Peter McCawley, Lynn Accorda, and RMA Services, LLC (incorporated by reference to the Registrant’s Form 8-K filed November 1, 2013)
10.42	Unconditional Corporate Guaranty by Twin Cities Power Holdings, LLC in favor of New York Independent System Operator, Inc. dated December 2, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed December 10, 2013)

98

Exhibit Number	Description
10.43	Third Amendment to Employment Agreement dated March 1, 2014 between Twin Cities Power Holdings, LLC and Stephanie Staska (*) (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed March 26, 2013)
10.44	First Amendment to Employment Agreement dated March 24, 2014 between Twin Cities Power Holdings, LLC and Timothy Krieger (*) (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed March 26, 2013)
12.1	Computation of Ratio of Earnings to Fixed Charges
12.2	Computation of Ratio of Earnings to Fixed Charges and Preferred Distributions
16	Letter from Cummings, Keegan & Co., PLLP regarding change in certifying accountant (incorporated by reference to Exhibit 16 to the Registrant’s Form S-1/A filed March 30, 2012)
21	List of Subsidiaries of the Registrant
23.1	Consent of Baker Tilly Virchow Krause, LLP
24.1	Powers of Attorney (included on signature page)
31.1	Certification of Chief Executive Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2	Certification of Chief Financial Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
32.1	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document
101.LAB*	XBRL Labels Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document

____________

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

99

Signatures

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

		TWIN CITIES POWER HOLDINGS, LLC
		/S/ TIMOTHY S. KRIEGER
Dated: March 28, 2014	By:	Timothy S. Krieger
		Chief Executive Officer, President and Chairman of the Board (principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report on Form 10-K has been signed below on the dates set forth by the following persons on behalf of the registrant and in the capacities indicated:

	/S/ TIMOTHY S. KRIEGER
Dated: March 28, 2014	Timothy S. Krieger
	Chief Executive Officer, President and Chairman of the Board (principal executive officer)
	/S/ WILEY H. SHARP III
Dated: March 28, 2014	Wiley H. Sharp III
	Vice President – Finance and Chief Financial Officer (principal accounting and financial officer)
	/S/ MARK A. COHN
Dated: March 28 2014	Mark A. Cohn
	Governor
	/S/ WILLIAM M. GOBLIRSCH
Dated: March 28 2014	William M. Goblirsch
	Governor
	/S/ DAVID B. JOHNSON
Dated: March 28 2014	David B. Johnson
	Governor

100

EX-12.1

Exhibit 12.1 - Computation of Ratio of Earnings to Fixed Charges

Twin Cities Power Holdings, LLC and Subsidiaries

Computation of Ratio of Earnings to Fixed Charges

	For the Years Ended December 31,
	2013		2012		2011		2010
Earnings
Income (loss) before income taxes	$	2,140,139	$	1,986,735	$	11,680,200	$	6,294,258
+ Fixed Charges		1,703,378		1,236,030		3,188,517		7,309,324
= Earnings	$	3,843,517	$	3,222,765	$	14,868,717	$	13,603,582
Fixed Charges
Interest expense	$	1,501,935	$	1,065,414	$	3,027,621	$	7,172,119
+ Approximation of interest in rental expense (1)		150,023		165,605		160,896		137,205
+ Amortization of deferred financing costs (2)		51,420		5,011		–		–
= Fixed Charges	$	1,703,378	$	1,236,030	$	3,188,517	$	7,309,324
Ratio of Earnings to Fixed Charges		2.26x		2.61x		4.66x		1.86x

____________

1 - "Approximation of interest in rental expense" is equal to one-third of total operating lease rental expense as reported in the notes to the consolidated financial statements, with the remaining two-thirds considered to be depreciation. Total operating lease expense is as follows:

Total lease expense $ 450,069 $ 496,816 $ 482,689 $ 411,615

2 - As reported in the notes to the consolidated financial statements.

EX-12.2

Exhibit 12.2 - Computation of Ratio of Earnings to Fixed Charges and Preferred Distributions

Twin Cities Power Holdings, LLC and Subsidiaries

Computation of Ratio of Earnings to Fixed Charges and Preferred Distributions

	For the Years Ended December 31,
	2013		2012		2011		2010
Earnings
Income (loss) before income taxes	$	2,140,139	$	1,986,735	$	11,680,200	$	6,294,258
+ Fixed Charges		2,252,414		1,739,280		3,188,517		7,309,324
= Earnings	$	4,392,553	$	3,726,015	$	14,868,717	$	13,603,582
Fixed Charges
Interest expense	$	1,501,935	$	1,065,414	$	3,027,621	$	7,172,119
+ Approximation of interest in rental expense (1)		150,023		165,605		160,896		137,205
+ Amortization of deferred financing costs (2)		51,420		5,011		–		–
+ Distributions - preferred (3)		549,036		503,250		–		–
= Fixed Charges	$	2,252,414	$	1,739,280	$	3,188,517	$	7,309,324
Ratio of Earnings to Fixed Charges
and Preferred Distributions		1.95x		2.14x		4.66x		1.86x

1 - "Approximation of interest in rental expense" is equal to one-third of total operating lease rental expense as reported in the notes to the consolidated financial statements, with the remaining two-thirds considered to be depreciation. Total operating lease expense is as follows:

Total lease expense 450,069 496,816 482,689 411,615

2 - As reported in the notes to the consolidated financial statements.

3 - As reported in on the consolidated statements of cash flows.

EX-21

Exhibit 21 - List of Subsidiaries of Registrant

Subsidiaries of Twin Cities Power Holdings, LLC At December 31, 2013
Company Name	Jurisdiction of Organization	Status	Tier
Twin Cities Power, LLC	Minnesota	Active	First
Chesapeake Trading Group, LLC	Minnesota	Active	Second
Summit Energy LLC	Minnesota	Active	Second
TC Energy Trading, LLC	Minnesota	Inactive	Second
Twin Cities Power Services, LLC	Minnesota	Inactive	Second
Vision Consulting, LLC	Minnesota	Inactive	Second
Cygnus Partners, LLC	Minnesota	Active	First
Cygnus Energy Futures, LLC	Minnesota	Active	Second
Twin Cities Energy, LLC	Minnesota	Inactive	First
Twin Cities Power – Canada, Ltd.	Alberta	Inactive	Second
Retail Energy Holdings, LLC	Minnesota	Active	First
Town Square Energy, LLC	Delaware	Active	Second
Discount Energy Group, LLC (effective January 2, 2014)	Delaware	Active	Second
Cyclone Partners, LLC	Minnesota	Active	First

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statement on Form S-1 (File No. 333-179460) of Twin Cities Power Holdings, LLC and Subsidiaries of our report dated March 28, 2014, relating to the consolidated financial statements, which appears in this annual report on Form 10-K for the year ended December 31, 2013.

Minneapolis, Minnesota

March 28, 2014

EX-31.1

EXHIBIT 31.1

CHIEF EXECUTIVE OFFICER CERTIFICATION

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Timothy S. Krieger, certify that:

1. I have reviewed this Annual Report on Form 10-K of Twin Cities Power Holdings, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted account principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of governors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 28, 2014

/s/ Timothy S. Krieger   

Timothy S. Krieger

Chairman of the Board, Chief Executive Officer, and President

EX-31.2

EXHIBIT 31.2

CHIEF FINANCIAL OFFICER CERTIFICATION

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Wiley H. Sharp III, certify that:

1. I have reviewed this Annual Report on Form 10-K of Twin Cities Power Holdings, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations, and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted account principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of governors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 28, 2014

/s/ Wiley H. Sharp III   

Wiley H. Sharp III

Vice President – Finance and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. §1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Twin Cities Power Holdings, LLC (the “Company”) on Form 10-K for the year ended December 31 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Timothy S. Krieger, Chief Executive Officer of the Company, and I, Wiley H. Sharp III, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Timothy S. Krieger    

Timothy S. Krieger

Chairman of the Board, Chief Executive Officer and President

Date: March 28, 2014

/s/ Wiley H. Sharp III   

Wiley H. Sharp III

Vice President – Finance and Chief Financial Officer

Date: March 28, 2014

XML

2. Summary of Significant Accounting Policies (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Gain (loss) from foreign currency translations	$ 2,261	$ (16,678)

XML

11. Deferred Financing Costs (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Deferred Financing Costs
Amortization of deferred financing costs	$ 51,420	$ 5,011

XML

8. Fair Value Measurements (Details-Level 3) (Fair Value Inputs Level 3, USD $)	12 Months Ended
	Dec. 31, 2013
Fair Value Inputs Level 3
Balance - December 31, 2012	$ 0
Total gains and losses:
Included in other comprehensive income	0
Included in earnings	0
Purchases	353,504
Sales	0
Transfers into Level 3	0
Transfers out of Level 3	0
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	$ 0

XML

12. Land Held for Development; Mortgage Receivable (Details Narrative) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Land Held For Development Mortgage Receivable
Land held for development	$ 110,477	$ 0

XML

7. Marketable Securities (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Marketable securities cost	$ 250,237
Gross unrealized gains	5,836
Gross unrealized losses	(69)
Marketable securities	256,004	0
U.S. Equities [Member]
Marketable securities cost	224,415
Gross unrealized gains	5,836
Gross unrealized losses	0
Marketable securities	230,251
International Equities [Member]
Marketable securities cost	25,047
Gross unrealized gains	0
Gross unrealized losses	(69)
Marketable securities	24,978
Money Market Funds [Member]
Marketable securities cost	775
Gross unrealized gains	0
Gross unrealized losses	0
Marketable securities	$ 775

XML

10. Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of intangible assets

	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

XML

13. Debt (Details-Maturity schedule) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
2013	$ 0	$ 5,005,620
2014	5,122,596
Current maturities	5,122,596	5,005,620
2014	0	283,500
2015	1,266,590	350,690
2016	772,250	193,500
2017	549,140	281,755
2018	2,297,250	0
2019 & Thereafter	177,000	165,000
Long term debt	5,062,230	1,274,445
Total notes payable	$ 10,184,826	$ 6,280,065

XML

20. Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

20. Subsequent Events

From January 1 to March 27, 2014, the Company sold additional Subordinated Notes totaling $1,887,143 with a weighted average term of 25.3 months and bearing a weighted average interest rate of 13.60%.

On October 28, 2013, the Company entered into a Membership Interest Purchase Agreement with Gregg Ruth, Peter McCawley, and Lynn Acorda (collectively the “Sellers”) and a Management Services Agreement (the “MSA”) with RMA Services, LLC (“RMA”), a new company formed by the Sellers, pursuant to which the Company agreed to acquire all of the outstanding equity interests of Discount Energy Group, LLC (“DEG”) and purchase certain services from RMA following closing on a fixed price and performance incentive basis. DEG is licensed to provide electricity` to retail customers in Maryland, New Jersey, Ohio, and Pennsylvania. After receiving regulatory approval from FERC, the acquisition closed on January 2, 2014.

Immediately prior to closing, DEG’s assets and liabilities and equity totaled $539,289. At closing, cash and accounts receivable totaling $245,421 and accounts payable of $205,855 were transferred to RMA. At closing, TCPH paid cash to, or on behalf of, the Sellers and RMA totaling $637,000 consisting of $300,000 for the Sellers’ equity interests, $282,000 representing the net amounts on deposit with PJM and certain utilities, and $55,000 as an advance on the ultimate purchase price of certain customer accounts. Also at closing, liabilities of the Sellers and RMA totaling $596,795 were satisfied, including the $140,000 note payable to TCPH. Consequently, at closing, the Sellers received cash of $54,557.

TCPH paid total consideration for the equity of DEG of $742,283, consisting of $582,000 in cash and $162,726 in assumption of accounts payable. Of this total consideration, $281,569 was allocated to deposits, $12,300 to prepaid expenses, and $448,414 to intangible assets, which will be amortized over 24 months using the straight line method.

On January 6, 2014 TCPH received a notice from the Internal Revenue Service notifying that the Company’s 2012 return was under review by the Department.

On March 17, 2014, the Company invested $1,000,000 in a privately placed Convertible Promissory Note to be issued by Ultra Green Packaging, Inc. (“Ultra Green”) once the offering minimum of $2,000,000 has been achieved. The notes will mature five years from the date of issuance and bear a fixed interest rate of 10% per annum. Interest will accrue until December 31, 2014, at which time all accrued and unpaid interest will become due and payable. Thereafter, interest will be due and payable on a monthly basis. At the option of the holders, the notes will be convertible prior to or at maturity in shares of Ultra Green’s Series B Preferred Stock.

On March 25, 2014, the Company’s note payable to John O. Hanson was paid in full.

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

XML

9. Equipment and Furniture (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Abstract]
Depreciation expense including leasehold amortization expense	$ 186,267	$ 210,989

XML

4. Accounting for Derivatives and Hedging Activities (Details-Derivative assets and liabilities) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Energy commodity contracts
Derivatives, Fair Value [Line Items]
Designated as cash flow hedging instruments Fair Value Asset Derivatives	$ 417,310	$ 63,571
Not designated as hedging instruments Fair Value Asset Derivatives	717,606	1,149,995
Designated as cash flow hedging instruments Liability Derivatives	(60,695)	(158,880)
Not designated as hedging instruments Liability Derivatives	(757,828)	(1,039,400)
Total derivative instruments
Derivatives, Fair Value [Line Items]
Derivative assets	1,134,916	1,213,566
Derivative Liabilities	(818,523)	(1,198,280)
Cash in collateral and deposit accounts	10,168,055	12,009,737
Trading accounts and deposits, asset derivatives	11,302,971	13,223,303
Trading accounts and deposits, liability derivatives	$ (818,523)	$ (1,198,280)

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16. Ownership (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Schedule of Company's ownership

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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10. Intangible Assets (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Goodwill and Intangible Assets Disclosure [Abstract]
Total amortization	$ 319,348	$ 34,674

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14. Leases (Details-Minimum lease payments) (USD $)	Dec. 31, 2012
Leases [Abstract]
2014	$ 314,000
2015	293,000
2016	243,000
2017	209,000
2018	5,000
Total	$ 1,064,000

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8. Fair Value Measurements (Details-Recurring Basis) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading accounts and deposits	$ 10,484,448	$ 12,025,023
Investment securities	256,004
Mortgage note receivable	353,504
Fair Value Inputs Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading accounts and deposits	10,484,448	12,025,023
Investment securities	256,004
Mortgage note receivable	0
Fair Value Inputs Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading accounts and deposits	0	0
Investment securities	0
Mortgage note receivable	0
Fair Value Inputs Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading accounts and deposits	0	0
Investment securities	0
Mortgage note receivable	$ 353,504

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4. Accounting for Derivatives and Hedging Activities

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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.

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

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14. Leases (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Leases [Abstract]
Total lease expense for office space and equipment	$ 450,069	$ 496,816

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4. Accounting for Derivatives and Hedging Activities (Details-Gain/Loss in AOCI) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash flow hedge
Gain (Loss) Recognized in AOCI on Derivatives	$ 685,936	$ (82,032)
Cost of energy sold
Gain (Loss) Reclassified from AOCI to Income	$ 247,290	$ 5,683

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5. Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2013

Accounts Receivable Tables

Schedule of accounts receivable

	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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4. Accounting for Derivatives and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Company's derivative assets and liabilities

	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	)

Summary of gain or loss recognized in AOCI or earnings for derivatives designated as cash flow hedges

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

Changes in accumulated other comprehensive income

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

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13. Debt (Details-Notes Payable) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Notes payable	$ 10,184,826	$ 6,280,065
HTS Note Payable
Notes payable	0	3,400,262
Sunseri Note Payable
Notes payable	0	666,665
Hanson Note Payable
Notes payable	200,000	200,000
Renewable Unsecured Subordinated Notes
Notes payable	$ 9,984,826	$ 2,013,138

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4. Accounting for Derivatives and Hedging Activities (Details-Changes in AOCI) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Beginning balance	$ 457,279	$ 623,667
Other comprehensive income before reclassifications	490,400	(166,388)
Amounts reclassified from AOCI	(247,290)	0
Net current period other comprehensive income (loss)	243,110	(166,388)
Ending balance	700,389	457,279
Foreign Currency
Beginning balance	539,311	623,667
Other comprehensive income before reclassifications	(201,303)	(84,356)
Amounts reclassified from AOCI	0	0
Net current period other comprehensive income (loss)	(201,303)	(84,356)
Ending balance	338,008	539,311
Cash Flow Hedges
Beginning balance	(82,032)
Other comprehensive income before reclassifications	685,936	(82,032)
Amounts reclassified from AOCI	(247,290)	0
Net current period other comprehensive income (loss)	438,646	(82,032)
Ending balance	356,614	(82,032)
Available for Sale Securities
Beginning balance	0
Other comprehensive income before reclassifications	5,767
Amounts reclassified from AOCI	0
Net current period other comprehensive income (loss)	5,767
Ending balance	$ 5,767

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7. Marketable Securities (Tables)

12 Months Ended

Dec. 31, 2013

Marketable Securities Tables

Summary of cost and estimated fair value of available-for-sale 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

Unrealized losses on, and fair value of, securities positions

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

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8. Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of the amounts of assets measured at fair value on a recurring basis

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

Fair Value Measurement Using Significant Unobservable Inputs (Level 3)

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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3. Cash

12 Months Ended

Dec. 31, 2013

Cash-unrestricted:

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.

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

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9. Equipment and Furniture (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

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

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3. Cash (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Cash-unrestricted:
Credit requirement	$ 2,185,175	$ 3,445,912
Available credit	8,299,273	8,579,111
Trading accounts and deposits	$ 10,484,448	$ 12,025,023

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11. Deferred Financing Costs (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Deferred Financing Costs
Deferred financing costs	$ 393,990	$ 393,990
Less: accumulated amortization	(56,431)	(5,011)
Deferred financing costs, net	$ 337,559	$ 388,979

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Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash	$ 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	0
Marketable securities	256,004	0
Prepaid expenses and other 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	305,978	125,326
Deferred financing costs, net	337,559	388,979
Cash - restricted	320,188	0
Land held for development	110,477	0
Mortgage note receivable	353,504	0
Total assets	17,561,606	16,263,487
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	0	15,867
Notes payable, related parties	0	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	0
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 equity	0	2,745,000
Members' equity
Series A preferred equity	2,745,000	0
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

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5. Accounts Receivable (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Accounts receivable - trade	$ 1,315,209	$ 2,191,267
Wholesale Trading
Accounts receivable - trade	168,953	1,756,926
Retail Energy Services -Billed
Accounts receivable - trade	944,100	235,996
Retail Energy Services - Unbilled
Accounts receivable - trade	$ 202,156	$ 198,345

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1. Organization

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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.

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.

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13. Debt (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Accrued interest on Subordinated notes	$ 354,094	$ 50,553
Subordinated Notes outstanding	9,984,826
Interest payments on subordinated notes	$ 443,367	$ 16,587

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13. Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of notes payable

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

Schedule of notes payable by maturity

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

Schedule of subordinated notes outstanding

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

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19. Segment Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Wholesale trading revenue, net	$ 25,305,723	$ 18,255,932
Retail electricity revenue	7,479,775	817,641
Revenues	32,785,498	19,073,573
Cost of retail electricity sold	7,760,674	763,943
Retail sales and marketing	493	0
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
Operating costs and expenses	29,175,957	16,035,766
Operating income (loss)	3,609,541	3,037,807
Capital expenditures	1,059,268	288,728
Segment Identifiable Assets
Cash - unrestricted	3,190,495	771,852	971,081
Cash in trading accounts	10,484,448	12,025,023
Accounts receivable - trade	1,315,209	2,191,267
Note receivable	140,964	0
Marketable securities	256,004	0
Prepaid expenses and other assets	242,482	189,808
Total current assets	15,629,602	15,177,950
Equipment and furniture, net	504,298	571,232
Intangible assets, net	305,978	125,326
Deferred financing costs, net	337,559	388,979
Cash - restricted	320,188	0
Land held for development	110,477	0
Mortgage note receivable	353,504	0
Total assets	17,561,606	16,263,487
Segment Identifiable Liabilities and Equity
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	60,339
Notes payable	200,000	4,266,927
Subordinated notes	4,922,596	738,693
Obligations under NCA	250,000	0
Total current liabilities	7,750,993	8,590,026
Subordinated notes	5,062,230	1,274,445
Total liabilities	12,813,223	9,864,471
Series A preferred equity	2,745,000	0
Redeemable preferred equity	0	2,745,000
Common equity	1,302,994	3,196,737
AOCI	700,389	457,279	623,667
Total members' equity	4,748,383	3,654,016	3,062,671
Total liabilities & equity	17,561,606	16,263,487
Wholesale Energy Trading
Wholesale trading revenue, net	25,091,983	18,255,932
Revenues	25,091,983	18,255,932
Compensation and benefits	11,041,126	7,201,424
Professional fees	2,996,730	1,346,547
Other general and administrative	7,314,319	5,044,571
Trading tools and subscriptions	849,959	931,437
Operating costs and expenses	22,202,134	14,523,979
Operating income (loss)	2,889,849	3,731,953
Capital expenditures	32,567	13,908
Segment Identifiable Assets
Cash - unrestricted	1,988,248	336,909
Cash in trading accounts	8,581,233	11,605,023
Accounts receivable - trade	168,952	1,756,926
Prepaid expenses and other assets	87,499	75,379
Total current assets	10,825,932	13,774,237
Equipment and furniture, net	438,047	82,170
Total assets	11,263,979	13,856,407
Segment Identifiable Liabilities and Equity
Accounts payable - trade	619,840	780,792
Accrued expenses		189
Accrued compensation	299,439	1,969,388
Total current liabilities	919,279	2,750,369
Total liabilities	919,279	2,750,369
Investment in subsidiaries	10,006,692	10,566,727
AOCI	338,008	539,311
Total members' equity	10,344,700	539,311
Total liabilities & equity	11,263,979	13,856,407
Retail Energy Services
Wholesale trading revenue, net	213,740
Retail electricity revenue	7,479,775	817,641
Revenues	7,693,515	817,641
Cost of retail electricity sold	7,760,674	763,943
Retail sales and marketing	493
Compensation and benefits	194,486	93,879
Professional fees	225,439	177,681
Other general and administrative	868,266	538,142
Trading tools and subscriptions	41,291	13,761
Operating costs and expenses	9,090,649	1,587,406
Operating income (loss)	(1,397,134)	(769,765)
Capital expenditures	62,308	160,000
Segment Identifiable Assets
Cash - unrestricted	285,419
Cash in trading accounts	1,903,215	420,000
Accounts receivable - trade	1,146,257	434,341
Note receivable	140,964
Prepaid expenses and other assets	19,728
Total current assets	3,495,583	854,341
Equipment and furniture, net	66,251	6,199
Intangible assets, net	55,978	125,326
Total assets	3,617,812	985,866
Segment Identifiable Liabilities and Equity
Accounts payable - trade	415,804	116,693
Accrued expenses	666,959	66,565
Total current liabilities	1,082,763	183,258
Total liabilities	1,082,763	183,258
Investment in subsidiaries	2,178,435	884,640
AOCI	356,614	(82,032)
Total members' equity	2,535,049	(82,032)
Total liabilities & equity	3,617,812	985,866
Real Estate Development [Member]
Other general and administrative	13,060
Operating costs and expenses	13,060
Operating income (loss)	(13,060)
Capital expenditures	784,169
Segment Identifiable Assets
Cash - restricted	320,188
Land held for development	110,477
Mortgage note receivable	353,504
Total assets	784,169
Segment Identifiable Liabilities and Equity
Investment in subsidiaries	784,169
Total members' equity	784,169
Total liabilities & equity	784,169
Corporate, Net of Eliminations
Compensation and benefits	2,008,229	1,600,148
Professional fees	1,172,507	1,658,890
Other general and administrative	(5,342,128)	(3,334,657)
Trading tools and subscriptions	31,506
Operating costs and expenses	(2,129,886)	(75,619)
Operating income (loss)	2,129,886	75,619
Capital expenditures	180,224	114,820
Segment Identifiable Assets
Cash - unrestricted	916,828	434,943
Marketable securities	256,004
Prepaid expenses and other assets	135,255	114,429
Total current assets	1,308,087	549,372
Equipment and furniture, net		482,863
Intangible assets, net	250,000
Deferred financing costs, net	337,559	388,979
Total assets	1,895,646	1,421,214
Segment Identifiable Liabilities and Equity
Accounts payable - trade		571,816
Accrued expenses	16,597	3,624
Accrued compensation		15,000
Accrued interest	359,758	60,339
Notes payable	200,000	4,266,927
Subordinated notes	4,922,596	738,693
Obligations under NCA	250,000
Total current liabilities	5,748,951	5,656,399
Subordinated notes	5,062,230	1,274,445
Total liabilities	10,811,181	6,930,844
Investment in subsidiaries	(12,969,296)	(11,451,367)
Series A preferred equity	2,745,000
Redeemable preferred equity		2,745,000
Common equity	1,302,994	3,196,737
AOCI	5,767
Total members' equity	(8,915,535)	3,196,737
Total liabilities & equity	$ 1,895,646	$ 1,421,214

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17. Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

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.

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14. Leases (Tables)

12 Months Ended

Dec. 31, 2013

Leases [Abstract]

Key terms of the various leases for office space

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

Future minimum lease payments

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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19. Segment Information

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

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.

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

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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2. Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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.

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.

“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”.

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”.

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.

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.

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Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Revenue
Wholesale trading revenue, net	$ 25,305,723	$ 18,255,932
Retail electricity revenue	7,479,775	817,641
Total revenue	32,785,498	19,073,573
Costs and expenses
Cost of retail electricity sold	7,760,674	763,943
Retail sales and marketing	493	0
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
Total operating expenses	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)
Total other income (expense)	(1,469,402)	(1,051,072)
Income before income taxes	2,140,139	1,986,735
Income tax provision (benefit)	8,823	56,124
Net income	2,131,316	1,930,611
Preferred distributions	(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	0
Comprehensive income	$ 1,825,390	$ 1,260,973

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12. Land Held for Development; Mortgage Receivable

12 Months Ended

Dec. 31, 2013

Land Held For Development Mortgage Receivable

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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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013
Document And Entity Information
Entity Registrant Name	Twin Cities Power Holdings, LLC
Entity Central Index Key	0001541354
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float	$ 0
Entity Common Stock, Shares Outstanding	0
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

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13. Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

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

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. 

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

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Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 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 activities	4,350,357	2,889,339
Cash flows from investing activities
Purchase of marketable securities	(250,237)	0
Advance on note receivable	(140,964)	0
Purchase of equipment and furniture	(134,135)	(128,728)
Purchase of land held for development	(110,477)	0
Purchase of mortgage note receivable	(353,504)	0
Advance to restricted cash	(320,188)	0
Purchase of intangible assets	0	(160,000)
Net cash used in investing activities	(1,309,505)	(288,728)
Cash flows from financing activities
Deferred financing costs	0	(393,990)
Payments on notes payable	(4,316,927)	(3,276,338)
Issuance of renewable unsecured subordinated notes	8,625,775	2,094,138
Redemption of renewable unsecured subordinated notes	(654,087)	(81,000)
Preferred distributions	(549,036)	(503,250)
Common distributions	(3,491,890)	(553,761)
Redemption of common units	0	(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
Non-cash investing and financing activities:
Effective portion of cash flow hedge	356,614	82,032
Obligations under non-competition agreement	500,000	0
Series A preferred units issued in exchange for redeemable preferred units	2,745,000	0
Redeemable preferred units issued in exchange for certain notes payable	0	2,745,000
Accrued distributions - common	0	15,867
Unrealized gain on investment securities	5,767	0
Supplemental disclosures of cash flow information:
Cash payments for interest	1,186,649	1,166,111
Cash payments for income taxes, net	$ 8,823	$ 0

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7. Marketable Securities

12 Months Ended

Dec. 31, 2013

Investments, Debt and Equity Securities [Abstract]

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

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6. Notes Receivable

12 Months Ended

Dec. 31, 2013

Receivables [Abstract]

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”.

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18. Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

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.

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.

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.

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14. Leases

12 Months Ended

Dec. 31, 2013

Leases [Abstract]

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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10. Intangible Assets

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

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.

	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.

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14. Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 sqft
Square Footage	17,626
Monthly Rent	$ 23,166
Lakeville, Minnesota
Expiration Date	Dec. 31, 2017
Square Footage	11,910
Monthly Rent	12,264
Gilbert, Arizona
Expiration Date	Jan. 31, 2015
Square Footage	1,055
Monthly Rent	2,563
Tulsa, Oklahoma
Expiration Date	Feb. 28, 2016
Square Footage	1,800
Monthly Rent	3,750
East Windsor, New Jersey
Expiration Date	Sep. 30, 2016
Square Footage	1,150
Monthly Rent	2,339
Newtown, Pennsylvania
Expiration Date	Dec. 31, 2017
Square Footage	1,711
Monthly Rent	$ 2,250

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8. Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

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.

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

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

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.

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11. Deferred Financing Costs

12 Months Ended

Dec. 31, 2013

Deferred Financing Costs

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.

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10. Related Party Transactions (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Rent, real estate taxes and operating expenses paid	$ 227,200	$ 207,109
Non-Competition agreement payments	250,000
Interest expense associated with note to related parties	$ 31,550	$ 252,942

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16. Ownership (Details)	Dec. 31, 2013
Series A Preferred Units held	496
Series A Preferred Percent of Class	100.00%
Common units held	4,960
Common units Percent of Class	100.00%
Timothy S Krieger
Series A Preferred Units held	496
Series A Preferred Percent of Class	100.00%
Common units held	4,935
Common units Percent of Class	99.50%
Summer Enterprises
Series A Preferred Units held	0
Series A Preferred Percent of Class	0.00%
Common units held	25
Common units Percent of Class	0.50%

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11. Deferred Financing Costs (Tables)

12 Months Ended

Dec. 31, 2013

Deferred Financing Costs

Deferred financing costs

	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

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10. Intangible Assets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Goodwill and Intangible Assets Disclosure [Abstract]
Acquisition of CPandU	$ 160,000	$ 160,000
Non-competition agreement	500,000	0
Less: accumulated amortization	(354,022)	(34,674)
Intangible assets, net	$ 305,978	$ 125,326

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16. Ownership

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

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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2. Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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.

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.

“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”.

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”.

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.

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.

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9. Equipment and Furniture (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Abstract]
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

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3. Cash (Details Narrative) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Cash-unrestricted:
Restricted cash	$ 320,188	$ 0

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Consolidated Statements of Changes in Members' Equity (USD $)	Series A Preferred Equity	Common Equity	Accumulated Other Comprehensive Income	Total
Members' equity (deficit) at Dec. 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 income (loss)			(166,388)	(166,388)
Distributions - preferred		(503,250)		(503,250)
Distributions - common		(569,628)		(569,628)
Members' equity (deficit) at Dec. 31, 2012		3,196,737	457,279	3,654,016
Issued in exchange for redeemable preferred units	2,745,000			2,745,000
Redemption of common units				0
Net income		2,131,316		2,131,316
Other comprehensive income (loss)			243,110	243,110
Distributions - preferred		(549,036)		(549,036)
Distributions - common		(3,476,023)		(3,476,023)
Members' equity (deficit) at Dec. 31, 2013	$ 2,745,000	$ 1,302,994	$ 700,389	$ 4,748,383

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5. Accounts Receivable

12 Months Ended

Dec. 31, 2013

Receivables [Abstract]

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

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.

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13. Debt (Details-Subordinated notes) (USD $)	Dec. 31, 2013
Principal Amount	$ 9,984,826
Weighted Average Interest Rate	13.72%
Weighted average term	33.9 mos
3 months initial term
Principal Amount	302,752
Weighted Average Interest Rate	15.27%
6 months initial term
Principal Amount	186,103
Weighted Average Interest Rate	8.56%
1 year initial term
Principal Amount	3,634,711
Weighted Average Interest Rate	12.41%
2 years initial term
Principal Amount	1,176,900
Weighted Average Interest Rate	12.75%
3 years initial term
Principal Amount	904,440
Weighted Average Interest Rate	13.70%
4 years initial term
Principal Amount	435,885
Weighted Average Interest Rate	14.74%
5 years initial term
Principal Amount	3,167,035
Weighted Average Interest Rate	15.62%
10 years initial term
Principal Amount	$ 177,000
Weighted Average Interest Rate	13.66%

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3. Cash (Tables)

12 Months Ended

Dec. 31, 2013

Cash-unrestricted:

Schedule of cash

	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

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19. Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Information on segments

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

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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15. Defined Contribution 401(k) Savings Plan

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

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.