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, 2014

 

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 U.S. Electric Power Industry	11
Wholesale Trading	14
Wholesale Market Risk Management	16
Wholesale Credit Risk Management	17
Competition	18
Retail Energy Services	18
Retail Electric Bills	20
Billing Systems	21
Purchase of Receivables	22
Sales & Marketing	23
Energy Supply	24
Retail Credit Risk Management	25
Competition	27
Diversified Investments	27
Real Estate	27
Securities	29
Seasonality	29
Intellectual Property	30
Personnel	30
Regulatory Matters	30
Item 1A – Risk Factors	31
Risks Related to Our Businesses	31
Wholesale Trading	31
Retail Energy Services	32
Diversified Investments	34
Risks Related to Our Company	34
Risks Related to the Notes	37
Item 1B – Unresolved Staff Comments	37
Item 2 – Properties	38
Item 3 – Legal Proceedings	38
Item 4 – Mine Safety Disclosures	38
Part II	39
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6 – Selected Consolidated Financial Data	39
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation	40
Forward Looking Statements	40
Overview	41
Results of Operations	45
Liquidity, Capital Resources, and Cash Flow	50
Financing	52
Non-GAAP Financial Measures	54
Critical Accounting Policies and Estimates	54

 

 

Item 7A - Quantitative and Qualitative Disclosures about Market Risk	57
Commodity Price Risk	57
Interest Rate Risk	59
Liquidity Risk	59
Credit Risk	59
Foreign Exchange Risk	59
Item 8 – Financial Statements and Supplementary Data	60
Management’s Report on Internal Controls over Financial Reporting	60
Report of Independent Registered Public Accounting Firm	61
Consolidated Balance Sheets	62
Consolidated Statements of Comprehensive Income	63
Consolidated Statements of Cash Flows	64
Consolidated Statements of Changes in Members’ Equity	66
Notes to Consolidated Financial Statements	67
Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	98
Item 9A - Controls and Procedures	98
Item 9B – Other Information	98
Part III	99
Item 10 – Directors, Executive Officers, and Corporate Governance	99
Governors and Executive Officers	99
Board Composition, Election of Governors, and Committees	101
Risk Management Committee	101
Audit Committee	101
Compensation Committee	102
Item 11 - Executive Compensation	103
Summary Compensation Table	103
Outstanding Equity Awards	103
Governor Compensation	103
Retirement Plans	104
Potential Payments Upon Termination or Change-in-Control	104
Employment Agreements	104
Compensation Policies and Practices as They Relate to Risk Management	105
Indemnification of Governors and Executive Officers and Limitations of Liability	106
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	107
Item 13 – Certain Relationships, Related Transactions, and Director Independence	108
Item 14 – Principal Accountants’ Fees and Services	109
Audit and Non-Audit Fees	109
Audit Committee Pre-Approval Policies	109
Part IV	110
Item 15 – Exhibits, Financial Statement Schedules	110
Signatures	114
Exhibit 12.1 - Computation of Ratio of Earnings to Fixed Charges
Exhibit 12.2 - Computation of Ratio of Earnings to Fixed Charges and Preferred Distributions
Exhibit 21 - List of Subsidiaries of Registrant

 

 

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
AOCI		Accumulated other comprehensive income
Apollo		Apollo Energy Services, LLC, a wholly-owned, first-tier subsidiary of TCPH
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
CEF		Cygnus Energy Futures, LLC, a wholly-owned subsidiary of CP and a second-tier subsidiary of TCPH
CFTC		Commodity Futures Trading Commission, an independent agency of the United States government that regulates futures and option markets
CME		CME Group Inc. operates the CME (Chicago Mercantile Exchange), CBOT (Chicago Board of Trade), NYMEX (New York Mercantile Exchange), and COMEX (Commodities Exchange) derivatives exchanges and also offers certain cleared OTC products and services
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 wholly-owned, first-tier subsidiary of TCPH
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 TCPH
Cyclone		Cyclone Partners, LLC, a wholly-owned, first-tier subsidiary of TCPH
DEG		Discount Energy Group, LLC, a wholly-owned subsidiary of REH and a second-tier subsidiary of TCPH

 

 

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; LDC		Electric distribution company; may also be known as a local distribution company
EIA		Energy Information Administration, an independent agency within DOE
ERCOT		Electric Reliability Council of Texas, an ISO managing 85% of the electric Load of Texas and subject to oversight by the Public Utility Commission of Texas and the Texas Legislature but not FERC
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission, an independent regulatory agency within DOE
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
FTR		Financial Transmission Rights are financial instruments traded in certain ISOs and RTOs that entitle their holders to receive or pay charges based on congestion price differences in the day-ahead energy market across specific transmission paths. The value of an FTR reflects the difference in congestion prices rather than the difference in locational marginal prices, which includes energy, congestion, and marginal losses. FTRs are specified between any two pricing nodes on the system, including hubs, control zones, aggregates, generator buses, load buses and interface pricing points. FTRs are generally available in increments of 0.1 MW and for periods ranging from 1 month to multiple years. The value of an FTR can be positive or negative depending on the sink minus source congestion price difference, with a negative differences resulting in liability for the holder.
GAAP		Generally accepted accounting principles in the United States
ICE		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.
INC and DEC		An increment offer or “INC” is an offer in the day-ahead market to sell energy at a specified source bus. An INC will clear if the LMP at the bus equals or exceeds the offer price. A decrement bid or “DEC” is a bid in the day-ahead market to purchase energy at a specified sink bus. A DEC will clear if the LMP at the bus does not exceed the bid price.

 

 

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

 

 

Abbreviation or acronym		Definition
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 wholly-owned, first-tier subsidiary of TCPH
SEC		U.S. Securities and Exchange Commission, an independent agency of the United States government with primary responsibility for enforcing federal securities laws and regulating the securities industry and stock exchanges
SUM		Summit Energy, LLC, a wholly-owned subsidiary of TCP and a second-tier subsidiary of TCPH
TCE		Twin Cities Energy, LLC, an inactive, wholly-owned, first-tier subsidiary of TCPH
TCP		Twin Cities Power, LLC, a wholly-owned, first-tier subsidiary of TCPH
TCPC		Twin Cities Power – Canada, Ltd., an inactive, wholly-owned subsidiary of TCE and a second-tier subsidiary of TCPH
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

 

 

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

 

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

 

 

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

 

 

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 asset management activities including real estate development and investments in privately held businesses. Consequently, the Company has three major business segments used to measure its activity – wholesale trading, retail energy services, and diversified investments.

 

Organizational Structure

 

Our organizational structure (active entities only) as of March 25, 2015 is outlined below.

 

 

Key

Orange - Holding or management services company · Green – Wholesale Trading · Blue – Retail Energy Services · Gray – Diversified Investments

 

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, Cyclone, and Apollo.

 

 

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. MEF, a Minnesota limited liability company was formed on March 25, 2014.

 

Apollo was formed on October 27, 2014 as a wholly-owned subsidiary of the Company for the purpose of providing centralized services to the Company’s various other subsidiaries. Substantially all of the management rights and certain of the direct employees of TCPH were transferred to such entity as of January 1, 2015.

 

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 DEG, a retail energy business licensed by 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. On January 27, 2015, TSEC was incorporated in Alberta, Canada as a wholly-owned, first-tier subsidiary of REH and is a second-tier subsidiary of the Company.

 

On October 23, 2013, we formed 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 major locations. See “Properties”.

 

 

The U.S. Electric Power Industry

 

By virtually any measure, the electric power industry in the U.S. is substantial. According to EIA data, in 2013, the most recent year for which full data is available, the industry sold 3,725 TWh (up 0.8% from 2012) for more than $375.7 billion (up 3.3%) to over 146.4 million residential, commercial, and industrial customers (up 0.8%).

 

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, coupled with the essential nature of the service to modern life, have obvious implications for electricity market structures and regulations.

 

Today, the industry includes any entity producing, distributing, trading, or selling electricity. Physically, the nation’s power system includes generation resources, transmission lines, and retail distribution systems. As of the end of 2013, according to an analysis of the EIA’s Form 860, participants in the generation segment included investor-owned, publicly-owned, cooperative, and federal utilities, and non-utility power producers, including independent power producers and commercial and industrial entities that operate co-generation facilities. These entities owned over 19,000 generating units with total nameplate capacity of 1,164 GW. In addition to generation, the nation’s bulk power system also included over 190,000 circuit-miles of high-voltage (over 100kV) transmission lines. Our retail distribution network includes substations, wires, poles, metering, billing, and related support systems. Power marketers and retail energy providers do not own any generation, transmission, or distribution assets, but buy and sell in wholesale and retail markets. Finally, participants in wholesale power markets include banks, hedge funds, private equity firms, and trading houses.

 

The investor-owned portion of the industry, including utilities, retail energy providers, and non-utility generators, constitutes over 70% of the industry’s revenues, unit sales, and customers as shown by the table below. According to the Edison Electric Institute, a trade group representing the largest investor-owned utilities, in 2013, total energy operating revenues of shareholder-owned electric companies were $356.5 billion. As of December 31, 2013, consolidated holding company-level assets of these entities were $1.292 trillion, and of these assets, $791.8 billion were net property in service. In 2013, shareholder-owned electric utilities spent $16.9 billion on transmission investment, compared to $14.8 billion in 2012, are projected to spend $20.2 billion in 2014, and are planning to invest approximately $58 billion in 2015, 2016, and 2017. The total market capitalization of U.S. shareholder-owned electric companies was $504.4 billion on December 31, 2013.

 

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

 

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

 

 

U.S. Electric Power Industry Revenue, Unit Sales, Customers, and Average Retail Prices, All Sectors, 2013

		Entities (count)				Revenues ($millions)				% of Total				Unit Sales (TWh)				% of Total				Customers (000s)				% of Total				Avg Retail Price (¢/kWh)
By Energy Provider
Investor-owned utilities			217				219,680				58.5%				1,925				51.7%				86,679				59.2%				11.41
Retail energy providers			545				51,866				13.8%				723				19.4%				17,764				12.1%				7.17
Non-utility power producers			145				1,152				0.3%				18				0.5%				1				0.0%				6.52
Subtotal			907				272,698				72.6%				2,666				71.6%				104,443				71.3%				10.23
Cooperatives			859				41,986				11.2%				414				11.1%				18,755				12.8%				10.15
Municipally-owned utilities			828				38,128				10.1%				391				10.5%				14,924				10.2%				9.76
Public power districts			80				9,378				2.5%				106				2.8%				3,841				2.6%				8.85
State-owned utilities			12				5,862				1.6%				51				1.4%				1,338				0.9%				11.41
Federally-owned utilities			26				1,490				0.4%				37				1.0%				34				0.0%				3.99
Subtotal			946				54,858				14.6%				585				15.7%				20,137				13.8%				9.37
Adjustments (1)			65				6,174				1.6%				60				1.6%				3,070				2.1%				10.23
Total U.S.			2,777				375,716				100.0%				3,725				100.0%				146,406				100.0%				10.09
By Choice Type (2)
Type 0			2,675				270,549				72.0%				3,055				82.0%				102,477				70.0%				8.85
Type 1			74				58,655				15.6%				321				8.6%				23,534				16.1%				18.25
Type 2			7				27,402				7.3%				169				4.5%				11,805				8.1%				16.26
Type 3			9				9,733				2.6%				81				2.2%				4,168				2.8%				12.01
Type 4			12				9,376				2.5%				99				2.6%				4,422				3.0%				9.50
Subtotal			102				105,166				28.0%				670				18.0%				43,929				30.0%				15.71
Total U.S.			2,777				375,716				100.0%				3,725				100.0%				146,406				100.0%				10.09
By Census Region (3)
New England			210				17,558				4.7%				121				3.3%				7,098				4.8%				14.47
Middle Atlantic			247				47,399				12.6%				369				9.9%				18,019				12.3%				12.85
South Atlantic			388				76,733				20.4%				570				15.3%				29,952				20.5%				13.47
East North Central			394				54,229				14.4%				298				8.0%				22,134				15.1%				18.23
East South Central			246				27,737				7.4%				787				21.1%				9,470				6.5%				3.52
West North Central			514				26,716				7.1%				318				8.5%				10,651				7.3%				8.39
West South Central			291				48,110				12.8%				571				15.3%				17,270				11.8%				8.42
Mountain			244				25,073				6.7%				273				7.3%				10,598				7.2%				9.18
Pacific - contiguous			213				47,967				12.8%				402				10.8%				20,403				13.9%				11.93
Pacific - noncontiguous			30				4,194				1.1%				16				0.4%%				811				0.6%				26.59
Total US			2,777				375,716				100.0%				3,725				100.0%				146,406				100.0%				10.09

____________________

Source: Company analysis of U.S. EIA Form 861 data, released February 19, 2015, next release October 2015.

Notes

1 - Adjustments are required to reconcile federal and state reporting requirements.

2 - Retail choice types defined as follows: Type 0 - no retail customers have choice of generation services provider ("GSP"); Type 1 - all residential, commercial, and industrial customers in investor-owned utility ("IOU") service areas have choice of GSP; Type 2 - limited number of residential customers have choice, choice of commercial and industrial customers is capped; Type 3 - no residential customers have choice, choice of commercial and industrial customers is capped; and Type 4 - no residential customers have choice, choice of commercial and industrial customers is limited.

3 - Census regions defined as follows: New England - CT, ME, MA, NH, RI, VT; Middle Atlantic - NJ, NY, PA;  South Atlantic - DE, DC, FL, GA, MD, NC, SC, VA, WV; East North Central - IL, IN, MI, OH, WI; East South Central - AL, KY, MS, TN; West North Central - IA, KS, MN, MO, NE, ND, SD;  West South Central - AR, LA, OK, TX; Mountain - AZ, CO, ID, MT, NV, NM, UT, WY; Pacific-contiguous - CA, OR, WA; and Pacific-noncontiguous - AK, HI.

 

 

Today, wholesale prices are subject to a federal regulatory framework focused on ensuring fair competition and reliability of supply. At the state level, under the traditional system which most states continue to employ, a vertically integrated utility (a “full service provider”) is responsible for serving all consumers in a defined territory and customers are obligated to pay the regulated rate for their class of service.

 

However, in a state with a restructured or “deregulated” market, that is, the “restructured retail” business or one with retail choice, the generation, transmission, distribution, and retail marketing functions of the business are legally separated and pricing of energy is unbundled from delivery services.

 

U.S. Electric Power Industry Revenue, Unit Sales, Customers, and Average Retail Prices, 2013

			Revenues ($millions)				% of Total				Unit Sales (TWh)				% of Total				Customers (000s)				% of Total				Avg Retail Price (¢/kWh)
By Customer Type
Residential			169,131				45.0%				1,395				37.4%				127,880				87.3%				12.13
Commercial			138,533				36.9%				1,344				36.1%				17,782				12.1%				10.31
Industrial & other			68,052				18.1%				986				26.5%				744				0.5%				6.90
Total industry			375,716				100.0%				3,725				100.0%				146,406				100.0%				10.09
Residential			155,181				41.3%				1,291				34.7%				116,728				79.7%				12.02
Commercial			109,494				29.1%				1,082				29.0%				15,920				10.9%				10.12
Industrial & other			53,450				14.2%				792				21.3%				693				0.5%				6.75
Full service providers			318,125				84.7%				3,166				85.0%				133,341				91.1%				10.05
Residential			13,949				3.7%				103				2.8%				11,152				7.6%				13.49
Commercial			29,039				7.7%				262				7.0%				1,862				1.3%				11.08
Industrial & other			14,602				3.9%				194				5.2%				51				0.0%				7.54
Restructured retail			57,591				15.3%				559				15.0%				13,065				8.9%				10.30
Residential			7,777				2.1%				–				–				–				–				7.52
Commercial			18,186				4.8%				–				–				–				–				6.94
Industrial & other			11,120				3.0%				–				–				–				–				5.74
Energy only providers			37,083				9.9%				–				–				–				–				6.63
Residential			6,172				1.6%				–				–				–				–				5.97
Commercial			10,853				2.9%				–				–				–				–				4.14
Industrial & other			3,482				0.9%				–				–				–				–				1.80
Delivery service only			20,507				5.5%				–				–				–				–				3.67

____________________

Source: Company analysis of U.S. EIA Form 861 data, released February 19, 2015, next release October 2015.

 

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.

 

One of the unique aspects of certain wholesale electricity markets run by ISOs is the availability of “locational marginal prices” (“LMPs”), also known as “nodal pricing”. The theoretical price of electricity at each node on the network is calculated based on the assumptions that one additional kilowatt-hour is demanded at the node in question, and that the marginal cost to the system that would result from the optimized re-dispatch of available generating units to serve the load can establish the production cost of the additional energy. LMPs are typically quoted on a “real-time” and “day-ahead” basis. In the real-time market, prices at specific nodes on the grid are updated every 5 minutes based on current and targeted supply and demand. Day-ahead prices are for power to be delivered at a specified hour and transmission point during the next day.

 

LMPs vary by time and location due to physical system limitations, congestion, and loss factors; however, in an unconstrained system with no losses, all LMPs would be equal. This means that LMPs can be conceptually separated into three components - an energy price, a marginal congestion component or “MCC”, and a loss component or “MLC”.

 

As generators are dispatched to meet load, the energy transfer capacity of transmission lines is used. Bulk power systems must be operated to allow for continuity of supply even if a contingent event, like the loss of a line, generator, or transformer were to occur. At times, transmission lines may also reach their maximum thermal capacity. These “security constraints”, also known as “congestion”, limit the ability to use the least expensive generation. In other words, when constraints exist on a transmission network, there is a need for more expensive generation to be used, and separate prices on either side of a node give rise to congestion pricing to relieve the constraint and reduce line loadings.

 

Finally, since transmission lines act as resistors to the flow of energy, to receive a specific quantity at a particular destination, more than the expected quantity must be injected into the line at origination to compensate for losses.

 

Wholesale Trading

 

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.

 

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.

 

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. 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.

 

 

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

 

 

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

 

 

Wholesale 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.

 

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 “Item 7A - Quantitative and Qualitative Disclosures about Market Risk”.

 

 

Wholesale 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.

 

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 February 18, 2015, 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 - “AA-” by S&P and “A1” by Moody’s; 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 our DataLive proprietary software system described below in “Item 1 – Business – Intellectual Property” enhances our traders’ success.

 

Retail Energy Services

 

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

 

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

 

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

 

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

 

Suppliers, also known as retail energy providers (each, a “REP”), energy service companies (each, an “ESCO”), competitive energy providers (each, a “CEP”), or the like depending upon the state, are also licensed 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.

 

 

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

 

Type 1	All residential, commercial, and industrial customers may choose their energy provider. While this applies primarily in areas served by investor-owned utilities, in certain jurisdictions, customers of specific cooperatives and public utilities may also have choice but these instances are rare;
Type 2	A limited number of residential customers have choice and the choice of non-residential customers is capped, usually at a specific number of megawatt-hours per year;
Type 3	No residential customers have choice and the choice of non-residential customers is capped; and
Type 4	No residential customers have choice and the number of non-residential with choice is limited.

 

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

 

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

 

In the 14 areas where all rate classes had choice during 2013, according to EIA data, 25.584 million residential and 3.127 million non-residential customers were eligible to choose their supplier. Of these totals, 11.152 million residential (43.6%) and 1.913 million non-residential (61.2%) customers purchased over 559,210,000 MWh from competitive suppliers.

 

 

 

Retail Electric Bills

 

Unbundling of 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:

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

 

The following graph, prepared from EIA data, shows the composition of electric bills in Connecticut 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.

 

 

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. In POR areas, 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.

 

In states with retail choice but without POR programs - the “non-POR” jurisdictions - retailers are exposed to the credit risk of the customer. Beginning in late 2014, Massachusetts became a POR jurisdiction. 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 90 days (about 120 days from the last invoice date), the utility has the option to convert the customer to dual billing. In Ohio, the only POR service territory, is currently served by Duke Energy Ohio. The rest of the state is non-POR. The District of Columbia is in the process of becoming a POR jurisdiction.

 

POR Program Type	Retail Choice Type and Areas
Full or recourse	Type 1: Connecticut, Illinois, Maryland, Massachusetts, New Jersey, New York, Ohio - Duke, Pennsylvania
In progress	Type 1: District of Columbia, Ohio- AEP
None	Type 1: Delaware, Maine, New Hampshire, Ohio excluding Duke and AEP, Rhode Island, Texas
	Type 2: California
	Type 3: Michigan
	Type 4: Montana, Nevada, Oregon, Washington

 

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 S&P, Moody’s, and Fitch. “BBB-” by S&P or Fitch or “Baa3” by Moody’s are considered to be the lowest investment grades by market participants.

 

 

The table below summarizes the credit ratings of certain investor-owned utilities operating in Type 1 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, September 2014

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

2

2

BBB+

–

Maryland

POR

4

4

BBB

–

Massachusetts

POR

4

4

A-

–

New Hampshire

non-POR

3

3

A-

–

New Jersey

recourse POR

4

4

BBB+

–

New York

POR

8

6

BBB+

2

Ohio (Duke)

POR

1

1

BBB+

–

Ohio (non-Duke)

non-POR

5

5

BBB-

–

Pennsylvania

POR

11

7

BBB-

4

Rhode Island

non-POR

2

1

A-

1

Texas

non-POR

5

4

BBB+

1

Total/average

57

48

BBB+

9

 

Sales & Marketing

 

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 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.

 

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 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 Company is currently licensed as a competitive retail supplier in 8 of the 14 jurisdictions that allow full retail choice. Within the eight states in which we are licensed, there are a total of 36 investor-owned utility service territories and of this total, we are currently marketing our services in 15 with plans to market in additional territories by the end of 2015. During the course of 2015, we intend to apply for retail supplier licenses in additional states in the U.S. and Alberta, Canada.

 

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 2013-2014 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.

 

In 2014, we went to market through various channels including outbound telemarketing, brokerage relationships, and online comparison shopping engines. We generally price our contracts such that our offers provide savings compared to the standard offer default rates offered by the incumbent utilities. In 2014, we also experimented with other direct marketing methods such as radio and direct mail. As we expand our operations, we expect to continue to use these methods as well as others.

 

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.

 

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 instruments we use are principally physical forward contracts and registered derivative contracts. Under a physical contract, we agree to take delivery of a specified quantity of electricity at a specific location and specified time, the price of which is usually determined by reference to a market index. Under a derivative contract, we agree with a counterparty to 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 guidelines, adopted by our Risk Management Committee on July 23, 2014, are summarized as follows:

 

·

Approved hedging instruments include off-the-shelf and customized or shaped electricity futures, swap, and option products or others as approved by management.

 

·

For a given delivery month, hedges of forecasted energy sales to retail customers (“load”) shall be in place no later than one business day in advance of the beginning of such month as follows:

o

80% to 120% of on-peak load;

o

At least 50% of off-peak load for all months; and

o

At least 70% of off-peak load during winter and summer.

 

·

When possible, hedges shall 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 liquid hub that meets the criteria for a hedge that is expected to be "highly effective" under Accounting Standards Codification 815, Derivatives and Hedging, that is, prospective hedge effectiveness testing using the regression approach must show both a slope (m) greater than or equal to 0.80 and less than or equal to 1.25 and an R-squared correlation coefficient of greater than or equal to 0.80.

 

·

Appropriate memoranda on approved forms that designate specific derivative contracts for hedge accounting treatment shall be prepared except for intra-month and prompt month purchases.

 

Retail Credit Risk Management

 

In connection with the retail electricity business, retailers like the Company may provide trade credit to both utilities and retail customers. 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:

 

·

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

 

·

If a prospect is located in a non-POR area and is a residential account, we will check their three-bureau FICO score:

o

If the score is above a certain threshold, we will accept the account without a deposit.

o

If the score is below the threshold, we will accept the account with a deposit equal to the dollar value of 90 days of expected energy sales.

 

·

If a prospect is located in a non-POR area and is a non-residential account, we will check their trade credit score:

o

If the score is above the threshold level, we will accept the account without a deposit.

o

If the score is below the threshold, we will accept the account with a deposit equal to the dollar value of 90 days of expected energy sales.

 

·

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%.

 

·

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.

 

Under New Jersey’s recourse POR rules, retailers have no exposure to customer credit risk provided that the customer is billed via UCB. However, if an electric account is in default for 90 days (about 120 days from invoice date), the utility has the option to convert the customer to “dual billing”. New Jersey utilities periodically review their accounts receivable and designate “dual billers” as appropriate. This information is communicated to us and triggers the following procedures:

 

·

If an account is not designated as a “dual biller”, no collection action is required.

 

·

If an account is designated as a “dual biller”, then we will drop the account.

o

If no balance is due, then nothing needs to be done.

o

If a balance is due, an invoice will be sent to the customer. The customer has 30 days to respond with either a payment or a disputation.

§

If full payment is received, then it is applied to the balance due, and the account is closed.

§

If partial payment is received, then it is applied to the balance due, and 15 days later, a new invoice is sent requesting payment of the new balance.

§

If a payment is not received, then the account is added to the collection agency’s list which is updated if the amount exceeds $50.

	Ø	If the agency’s collection effort is successful, then it will notify us via email with respect to the total amount they were able to collect, followed within two weeks by a receipt and check for the amount collected, less their fee. Customer accounts are not credited until the agency’s check is received.
	Ø	If the collection effort is unsuccessful after 90 days, then the account balance will be written off.

 

 

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.

 

Diversified Investments

 

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

 

Real Estate

 

According to the Minneapolis Area Association of Realtors® 2014 Annual Report on the Twin Cities Housing Market:

 

“Two steps forward, one step back. That's how the 2014 housing recovery went in most local U.S. markets. It was another recovery year but not without its hurdles – some new, some familiar. Metrics like sales price and new listings showed improvement, while new home construction and inventory didn't quite meet expectations. Although the rate of improvement is uneven across areas, price tiers, and market segments, overwhelmingly encouraging data sets a positive tone for 2015.

 

While that data confirms that recovery is still underway, it also suggests that the 2014 recovery was not as strong as in 2013. Moderate inventory gains meant less robust – yet still mostly positive – price growth. Since prices have risen, the affordability picture isn't what it was in 2012 or 2013, though affordability remains above its long-term average. Factors such as inadequate mortgage liquidity, stagnant wage growth and student loan debt have served as impediments to both first-time and move-up buyers.”

 

 

The following table describes 2014’s residential real estate market conditions in the Twin Cities region as well as selected areas of interest.

 

Area Overview			2014 Total Closed Sales			Change from 2013			New Construc-tion Pct			Town-house/ Condo Pct			Distressed Pct			Cum-ulative Days on Market			Pct of Original Price Received
Twin Cities Region			49,541			-6.9%			7.0%			24.0%			16.5%			78			95.7%
Scott County			2,286			-7.4%			8.8%			25.1%			16.3%			83			96.1%
Credit River Twshp			25			-40.5%			12.0%			0.0%			4.0%			224			94.4%
Dakota County			6,000			-5.5%			6.9%			33.0%			16.0%			72			95.9%
Lakeville			1,003			-9.7%			17.1%			21.9%			12.1%			78			96.3%

 

Median Prices			2010			2011			2012			2013			2014			Change from 2013			Change from 2009
Twin Cities Region			169,900			150,000			167,900			192,000			205,739			7.2%			21.1%
Scott County			190,000			180,000			197,000			226,750			239,900			5.8%			26.3%
Credit River Twshp			400,000			392,000			438,000			449,000			537,000			19.6%			34.3%
Dakota County			175,000			156,000			170,500			200,000			215,000			7.5%			22.9%
Lakeville			225,000			205,000			226,000			258,000			272,000			5.4%			20.9%

____________________

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. During 2014, there was no substantial activity with respect to the project. Although Cyclone’s final plan for the property is yet to be decided upon, it is anticipated that about $600,000 in additional capital will be invested in the Bitterbush Pass project in 2015.

 

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 foreclosed on the note in April 2014 and thereby obtained title to the land.

 

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 then current plat of up to 40 attached residential building sites.

 

In addition to the purchase price of the mortgage note, the Company 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. On June 24, 2014, the cash collateral was exchanged for a letter of credit issued by Vermillion State Bank secured by a mortgage on the property.

 

 

During the course of 2014, the Company worked with the City of Lakeville to modify a portion of the previously approved development plan for the property and on August 21, 2014, the City issued final approval for 35 attached residential building sites. About $50,000 in additional capital was invested in the project during 2014 and $820,000 of construction financing for the first four spec/model homes was committed on November 21, 2014. Ground was broken for the first unit on December 15, 2014. Overall, the Company expects to invest an additional $2.0 million in 2015 with sales expected to commence in the second quarter.

 

Texas Avenue: On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon Holdings, LLC (“Kenyon”), a related party, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a $120,000 promissory note secured by the property and owed to Lakeview Bank. Kenyon is owned by Timothy S. Krieger, the Company’s primary owner and Chief Executive Officer, and Keith W. Sperbeck, its Vice President of Operations. In addition to the note, the Company paid $51,980 for closing costs, real estate taxes, and interest, bringing its investment in the lot to $171,957 as of December 31, 2014. Although Cyclone’s final plan for the property is yet to be decided upon, it expects to invest about $10,000 in holding costs during 2015.

 

Securities

 

Ultra Green: During 2014, the Company invested $1,500,000 in privately placed Series C Convertible Promissory Notes issued by Ultra Green Packaging, Inc. (“Ultra Green”). Ultra Green develops, manufactures, and markets “ecopaper” products made from wheat straw, bamboo, or sugarcane fibers and bioplastic products made from cornstarch. Ultra Green’s ecopaper and bioplastic products are certified as biodegradable and sustainable, and are compostable in about 160 days. Ultra Green was not profitable for the year ended December 31, 2014.

 

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

 

The C Notes will mature on December 31, 2019 and bear interest at a fixed rate of 10% per annum. Interest will accrue until June 30, 2015, at which time all accrued and unpaid interest will become due and payable. Thereafter, interest will be due and payable on a quarterly basis. Each dollar of C Note principal and accrued but unpaid interest is ultimately convertible into 100 shares of Ultra Green’s common stock.

 

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.

 

 

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 a Certificate of Copyright Registration Number TX7-717-805 from the U.S. Copyright Office for DataLive. We have also applied to the U.S. Patent and Trademark Office for a trademark on the DataLive name and the application is still pending. We employ two full time software engineers who develop software tools for our traders. In 2014 and 2013, we spent approximately $279,000 and $270,000, respectively, on the development of DataLive.

 

We have also developed a proprietary risk management database known as the “SQL Database”, which delivers price data to our risk manager.

 

On April 9, 2013, we received notice from the U.S. Patent and Trademark Office that the Town Square Energy name and mark was granted registration as U.S. Reg. No. 4,316,142.

 

In 2013 and 2014, we capitalized $60,265 and $47,188 of development costs of internal-use software for use in our retail business, to be amortized on a straight-line basis over 36 months.

 

Personnel

 

As of March 3, 2015, we employed 42 persons (40 full-time and 2 part-time), including 19 electricity traders, 1 risk manager, and 23 executives and administrative personnel. We also utilize the services of 7 independent contractors. We have entered into employment agreements with all of our traders and administrative employees and do not employ any unionized labor.

 

To attract and retain qualified personnel, particularly traders, we employ a competitive compensation system that incorporates dedicated capital and a payout of approximately 20-40% 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 CFTC with respect to energy futures contracts, the Federal Trade Commission, and 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.

 

 

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 such persons, not all of them have non-competition provisions. Accordingly, a trader may leave us at any time. Further, 64% and 77% of our wholesale trading segment’s revenue was generated by the top 5 traders in 2014 and 2013, respectively. 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 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.

 

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

 

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. 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 existing 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.

 

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 “Item 1 - Business – Wholesale Trading - Wholesale Credit Risk Management”.

 

 

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 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.

 

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 generators, wholesale suppliers, the ISOs, and energy distribution companies. The loss of use or destruction of third party facilities used to generate, transmit, and distribute 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.

 

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 environmental 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. 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. See “Item 1 - Business – Retail Energy Services – Retail Credit Risk Management”.

 

Our retail business depends 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.

 

Diversified Investments

 

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.

 

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 of FERC, including the Federal Power Act, 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 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.

 

See “Item 8 – Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements, Note 19 – Commitments and Contingencies, PJM Up-To-Congestion Fees”.

 

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 agreements with wholesale electricity suppliers 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.

 

Historically, we have 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 25, 2015, we have raised over $22,420,020, of which $19,600,224 was outstanding as of that date. 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.

 

 

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 operations. 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.

 

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.

 

 

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 five 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			10,730			$	11,113			20
Cherry Hill, New Jersey			12/31/2015			175				400			–
Tulsa, Oklahoma			2/28/2016			1,800				3,750			8
East Windsor, New Jersey			9/30/2016			1,150				2,374			3
Newtown, Pennsylvania			12/31/2017			1,711				2,400			4
Chandler, Arizona			7/31/2019			2,712				4,068			7
Total						18,278			$	24,105			42

 

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 is Kenyon, 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 “Item 13 - Certain Relationships and Related Transactions, and Director Independence - Real Estate Leases”.

 

The lessor of our office space in Chandler, Arizona, Fulton Marketplace, LLC (“Fulton”), is a related party. On August 1, 2014, the Company and Fulton entered into a five year lease expiring July 31, 2019 at what it believes to be market rates. See “Item 13 - Certain Relationships and Related Transactions, and Director Independence - Real Estate Leases”.

 

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 “Item 13 - Certain Relationships and Related Transactions, and Director Independence - Real Estate Leases”.

 

Item 3 – Legal Proceedings

 

See “Item 8 - Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note 19 Commitments and Contingencies”.

 

Item 4 – Mine Safety Disclosures

 

Not applicable.

 

 

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 40 and our consolidated financial statements and notes thereto found in “Financial Statements and Supplementary Data” beginning on page 60.

 

		Years ended December 31
Dollars in thousands unless otherwise indicated		2014				2013
Statements of Operations Data
Net revenue		$	49,841			$	32,785
Total operating expenses			43,402				29,176
Operating income			6,440				3,610
Net other income (expense)			(2,661	)			(1,469	)
Income before income taxes			3,779				2,140
Provision for taxes			–				9
Net income			3,779				2,131
Preferred distributions			(549	)			(549	)
Net income attributable to common.		$	3,230			$	1,582
Ratio of earnings to fixed charges (1)			2.47	x			2.26	x
Balance Sheet Data
Cash and trading deposits		$	23,384			$	13,675
Total assets			31,770				17,562
Total debt			19,288				10,185
Total liabilities			29,072				12,813
Total members' equity			2,698				4,748

____________________

(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.

 

 

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.

 

Through our 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, we have three major business segments used to measure our activity – wholesale trading, retail energy services, and diversified investments.

 

Wholesale Trading

 

In general, the Company’s trading activities are characterized by the acquisition of electricity or other energy-related commodities at a given location and its delivery to another. “Financial” transactions settle in cash in an amount equal to the difference between the purchase and sale prices, while “physical” transactions are settled by the delivery of the commodity. ISO-traded financial contracts are also known as “virtual” trades, are outstanding overnight, and settle the next day. The Company also trades electricity and other energy derivatives on ICE, NGX, and CME and may hold an open interest in these contracts overnight or longer.

 

For the years ended December 31, 2014 and 2013, financial and virtual electricity represented 100% of our total trading volume in FERC-regulated markets, that is, we traded no physical power during these periods in our wholesale segment.

 

Retail Energy Services

 

On June 29, 2012, we acquired certain assets and the business of a small retail energy supplier serving residential and small commercial markets in Connecticut, and beginning on July 1, 2012, the Company began selling electricity to retail accounts. During late 2012 and early 2013, we applied for retail electricity supplier licenses for the states of Massachusetts, New Hampshire, and Rhode Island which were issued on various dates in 2013. On January 2, 2014, we acquired a retail energy business licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio. The eight states in which we are licensed incorporate the service territories of 36 investor-owned electric utilities and as of December 31, 2014, we were actively marketing its services in 10 of these.

 

Projected margins in specific utility service territories ultimately determine where we deploy our retail marketing resources and obtain customers. To date, our customer base consists largely of residential consumers with a few small commercial accounts. We primarily use direct marketing strategies to sell our services and our customers may typically cancel their contracts at any time.

 

Diversified Investments

 

On October 23, 2013, we formed Cyclone as a wholly-owned subsidiary to take advantage of certain perceived investment opportunities present in the residential real estate market. Specifically, we acquire and intend to develop land for resale, either as improved sites for construction of single- and multi-family homes or as completed dwellings. At various dates during 2014, we acquired certain privately placed securities for long term investment purposes.

 

 

Derivative Instruments

 

In our wholesale operations, we use derivative contracts for trading purposes, seeking to profit from perceived opportunities driven by expected changes in market prices. These contracts include exchange-traded instruments such as futures contracts, which are Level 1 instruments in the fair value hierarchy as well as FTRs available through certain FERC-regulated markets, which we consider to be Level 3 instruments as they are not regularly quoted. See “Item 8 – Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements, Note 8 – Fair Value Measurements” for additional information.

 

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

 

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

 

 

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

 

Open Derivative Contracts

As of December 31, 2014

Delivery

Final

Energy

Fair Value

Segment and contract type

Hub or zone

period

settlement

(MWh)

Asset

Liability

Wholesale Trading

Electricity futures

PJM West Hub peak

daily

daily

6,400

$

22,400

$

–

FTRs

MISO, NYISO, PJM

Q1 & Q2 2015

various

8,981,440

1,435,819

–

Electricity futures

AESO

Q1 2015

various

80,320

785,617

286,250

Electricity futures

AESO

Q2 2015

various

135,600

892,838

1,094,059

Electricity futures

AESO

Q3 2015

various

78,120

601,992

783,893

Subtotal

9,281,880

3,738,667

2,164,202

Retail Energy Services - Economic Hedges

Electricity futures

ISO-NE Mass Hub; PJM West Hub

Q1 2015

various

3,715

–

44,373

Electricity futures

PJM West Hub

Q2 2015

various

14,280

–

107,120

Natural gas futures

Henry Hub

Q2 2015

various

155,000

14,803

–

Electricity futures

PJM West Hub

Q3 2015

various

16,240

31,926

65,196

Natural gas futures

Henry Hub

Q3 2015

various

77,500

1,085

–

Electricity futures

PJM West Hub

Q4 2015

various

21,285

–

175,972

Subtotal

288,020

47,814

392,660

Retail Energy Services - Designated Cash Flow Hedges

Electricity futures

ISO-NE Mass Hub

Q1 2015

various

13,995

–

498,166

Electricity futures

ISO-NE Mass Hub

Q2 2015

various

16,120

–

184,378

Electricity futures

ISO-NE Mass Hub

Q3 2015

various

18,480

15,732

189,116

Electricity futures

ISO-NE Mass Hub

Q4 2015

various

352

–

7,480

Subtotal

48,947

15,732

879,140

Total

9,618,847

$

3,802,213

$

3,436,002

 

 

The table below details our open derivative contracts held for trading purposes, as undesignated economic hedges by our retail segment, and as designated cash flow hedges by our retail segment as of December 31, 2013:

 

Open Derivative Contracts

As of December 31, 2013

				Delivery				Final		Energy				Fair Value
Segment and contract type		Hub or zone		period				settlement		(MWh)				Asset				Liability
Wholesale Trading
Electricity futures		PJM West Hub			Q4 2013			various			23,200			$	–			$	55,448
Electricity futures		AESO			Q1 2014			various			60,600				614,592				631,708
Subtotal											83,800				614,592				687,156
Retail Energy Services - Economic Hedges
Electricity futures		ISO-NE Mass Hub, NYISO Zone G, and PJM West Hub			Q1 2014			various			22,200				60,226				36,724
Electricity futures		PJM West Hub			Q2 2014			various			5,120				1,932				7,660
Electricity futures		PJM West Hub			Q3 2014			various			5,120				40,856				4,872
Electricity futures		PJM West Hub			Q4 2014			various			5,120				–				21,416
Subtotal											37,560				103,014				70,672
Retail Energy Services - Designated Cash Flow Hedges
Electricity futures		ISO-NE Mass Hub			Q1 2014			various			12,200				289,338				–
Electricity futures		ISO-NE Mass Hub			Q2 2014			various			8,560				2,436				24,564
Electricity futures		ISO-NE Mass Hub			Q3 2014			various			5,120				11,588				251
Electricity futures		ISO-NE Mass Hub			Q4 2014			various			6,880				113,948				35,880
Subtotal											32,760				417,310				60,695
Total											154,120			$	1,134,916			$	818,523

 

 

Results of Operations

 

Years Ended December 31, 2014 and 2013

 

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		2014								2013								Increase (decrease)
		Dollars					Percent			Dollars					Percent			Dollars					Percent
Revenue
Wholesale trading revenue, net		$	38,612				77.5%			$	25,305				77.2%			$	13,307				52.6%
Retail electricity revenue			11,229				22.5%				7,480				22.8%				3,749				50.1%
Net revenue			49,841				100.0%				32,785				100.0%				17,056				52.0%
Operating costs & expenses
Cost of retail electricity sold			11,441				23.0%				7,761				23.7%				3,680				47.4%
Retail sales & marketing			325				0.7%				–				0.0%				325				na
Salaries, wages & related			21,722				43.6%				15,965				48.7%				5,757				36.1%
Professional fees			2,487				5.0%				1,673				5.1%				814				48.7%
Other general & administrative			6,094				12.2%				2,853				8.7%				3,241				113.6%
Trading tools & subscriptions			1,333				2.6%				923				2.7%				410				44.4%
Total operating expenses			43,402				87.1%				29,175				89.0%				14,227				48.8%
Operating income			6,439				12.9%				3,610				11.0%				2,829				78.4%
Interest expense			(2,293	)			-4.6%				(1,502	)			-4.6%				(791	)			52.7%
Interest income			143				0.3%				31				0.1%				112				361.3%
Loss on foreign currency exchange			(721	)			-1.4%				2				0.0%				(723	)			-36150%
Realized gain on sale of marketable securities			66				0.1%				–				0.0%				66				na
Other income			145				0.3%				–				0.0%				145				na
Other expense, net			(2,660	)			-5.3%				(1,469	)			-4.5%				(1,191	)			81.1%
Income before income taxes			3,779				7.6%				2,141				6.5%				1,638				76.5%
Income tax provision			–				0.0%				9				0.0%				(9	)			-100.0%
Net income			3,779				7.6%				2,132				6.5%				1,647				77.3%
Preferred distributions			(549	)			-1.1%				(549	)			-1.7%				–				0.0%
Net income attributable to common		$	3,230				6.5%			$	1,583				4.8%			$	1,647				104.0%

 

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

 

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

 

 

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

 

Market conditions during 2014 were characterized by abnormal weather, with a colder winter (281 more heating degree-days than normal), cooler summer (36 fewer cooling degree-days than normal), below-normal average temperature (52.5°F versus 53.7°F), and more expensive natural gas (up about 16% to $4.37/MCF versus the 5 year average of $3.76/MCF).

 

Comparing 2014 to 2013, 2014 was a bit cooler; HDD for the U.S. were 4,607 or 2% above 2013’s figure of 4,519 and CDD during 2014 totaled 1,271 compared to 1,273 in 2013. For 2014, the Henry Hub natural gas spot price averaged $4.37/MCF, 17% above 2013’s $3.73 mark. Supplies of gas during 2014 were adequate. Weekly storage levels averaged 2,222 BCF or 20% less than in 2013’s level of 2,784 and 22% lower than the 5 year average of 2,833.

 

	Years Ended December 31,
							Increase (decrease)
	Units						This year vs last year				This year vs LTA
	2014		2013		LTA (1)		Units		Percent		Units		Percent
U.S. Weather
Heating degree-days	4,607		4,519		4,326		88		2%		281		6%
Cooling degree-days	1,271		1,273		1,307		(2)		0%		(36)		-3%
Avg temperature (°F)	52.5°F		52.4°F		53.7°F		0.1°F		0%		-1.2°F		-2%
Natural Gas
Henry Hub spot price ($/MCF	4.37		3.73		3.76		0.64		17%		0.61		16%
Working gas in underground storage, Lower 48 states, EIA weekly estimates (BCF)	2,222		2,784		2,833		(562)		-20%		(610)		-22%

____________________

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

 

The average for the day-ahead PJM West Peak price during 2014 was $58.65/MWh with a standard deviation of $54.81 resulting in a coefficient of variation of 93%, compared to $43.26/MWh, $14.69, and 34% for 2013. The high for the year was $655.75/MWh and the low was $26.49. As shown by the table below, price levels and volatility were generally higher in 2014 as compared to 2013. It is interesting to note that most of the high prices and volatility of 2014 occurred in the first quarter.

 

 

			Years Ended December 31,
PJM West Hub Peak Day Ahead											Increase (decrease)
			2014				2013				Units				Percent
Price ($/MWh)
Average			58.65				43.26				15.38				36%
Maximum			655.75				153.85				501.89				326%
Minimum			26.49				29.70				(3.22)				-11%
Standard deviation			54.81				14.69				40.11				273%
Coefficient of variation (stdev ÷ avg)			93%				34%				59%				175%
Daily percentage changes
Average			2.5%				1.0%				1.5%				152%
Maximum			200.3%				127.6%				72.7%				57%
Minimum			-78.1%				-55.3%				-22.8%				41%
Standard deviation			25.8%				14.6%				11.1%				76%
Number of days
Up 10% or more			62				48				14				29%
Between 10% up and 10% down			131				165				(34)				-21%
Down 10% or more			62				42				20				48%

 

On December 30, 2014, FERC accepted the Company’s settlement offer dated November 14, 2014 with respect to their investigation into the activities of certain ex-employees in the MISO market. During the third quarter of 2014, disgorgement of profits and interest on such totaling $1,107,000 was recorded as a reduction of 2014’s revenue since the settlement related to trades that were initially recorded in revenue during the 13 month period from January 1, 2010 to January 31, 2011. With regard to the civil penalty of $2,500,000, the Company expensed it as an operating expense since the charge results from the Company’s operations. The final settlement agreement calls for payment of the disgorgement and interest amount to MISO with the penalty amount to the U.S. Treasury. The Company further agreed to implement certain procedures to improve compliance. The first installment of $500,000 was paid on December 31, 2014 and the remaining $3,107,013 will be paid in 16 equal quarterly installments of $194,188 each, beginning April 1, 2015.

 

As a result of these factors, for the year ended December 31, 2014, net wholesale trading revenue increased by $13,307,000 or 52.6% to $38,612,000 compared to $25,305,000 for 2013.

 

Retail electricity sales: We entered the retail energy services business on June 29, 2012. Revenue from the retail sale of electricity is recorded in the period in which customers consume the commodity, net of any applicable sales tax. Revenue applicable to electricity consumed by customers but not yet billed under the cycle billing method is estimated and accrued along with the related costs. Changes in estimates are reflected in operations in the period in which they are refined.

 

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

 

For the years ended December 31, 2014 and 2013, we recorded total revenues in our retail segment of $12,946,000 and $7,694,000, respectively. These totals consisted of retail energy sales of $11,229,000 in 2014 and $7,480,000 in 2013, up 50.1%, and wholesale trading revenues of $1,717,000 and $214,000, respectively, up 702%. During 2014, retail energy sales revenue increased principally as a result of an increase in prices. Our customer base consists largely of residential consumers with a few small commercial accounts.

 

 

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

 

			Years Ended December 31,
Key Operating Statistics											Increase (decrease)
(in units unless otherwise indicated)			2014				2013				Units				Percent
Retail electricity sales ($000s)			11,229				7,480				3,749				50.1%
Wholesale trading revenue, net ($000s)			1,717				214				1,503				702.3%
Total segment revenues ($000s)			12,946				7,694				5,252				68.3%
Unit sales (MWh)			112,378				99,231				13,147				13.2%
Weighted average retail price (¢/kWh)			9.99				7.54				2.45				32.6%
Customers receiving service, end of period			9,501				9,822				(321	)			-3.3%

 

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

 

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 years ended December 31, 2014 and 2013, the Company recorded no revenue but capitalized a total of $489,000 and $784,000, respectively, of costs associated with its real estate development activities, consisting primarily of purchases of land for development and actual development costs incurred.

 

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

 

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

 

During 2014, we hedged the cost of 76,915 MWh or 68% of the 112,378 MWh of electricity sold to our retail customers. For the year, our hedges had the effect of decreasing the cost of retail electricity sold by $91,508.

 

During 2013, we hedged the cost of 103,280 MWh or 105% of the 99,231 MWh of electricity sold to our retail customers. For the year, our hedges had the effect of decreasing the cost of retail electricity sold by $247,290.

 

 

As shown by the Open Derivative Contracts table on page 43, as of December 31, 2014, we had designated 48,947 MWh of electricity futures as hedges against the cost of expected 2015 electricity purchases and $863,000, representing the net loss on the effective portion of the hedges, was deferred in accumulated other comprehensive income and this entire amount is expected to be reclassified to cost of retail electricity sold by December 31, 2015.

 

As of December 31, 2013 as shown by the Open Derivative Contracts table on page 44, we had designated 32,760 MWh of electricity futures as hedges against the cost of expected 2014 electricity purchases. $357,000, representing the net gain on the effective portion of the hedges, was deferred in AOCI and this entire amount was reclassified to cost of retail electricity sold by December 31, 2014.

 

In total, during 2014 and 2013, we recorded costs of retail electricity sold of $11,441,000 and $7,761,000, respectively, resulting in a gross profit of $1,506,000 in 2014 and a gross loss of $67,000 in 2014. If the economic hedges were treated in the same way as that of the designated hedges, that is, with gains decreasing costs of sales with losses increasing such, gross margins would have been 12.6% in 2014 and -0.9% for 2013.

 

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

 

During 2014, we spent $325,000 on retail sales and marketing, principally on outbound telemarketing in connection with the DEG brand, compared to zero in 2013.

 

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

 

For 2014, salaries, wages, and related costs increased by $5,757,000 or 36.1% to $21,722,000 compared to $15,965,000 for 2013. Our personnel expense is directly related to the revenue we record, since our trader’s compensation is tied to revenue production, and this increase in expense is in line with the increase in revenues.

 

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

 

For 2014, professional fees increased by $814,000 to $2,487,000 compared to $1,673,000 in 2013. A majority of the increase is due to the acquisition of DEG that incurred $597,000 of professional fees for outside services. The Company also continues to incur legal fees in 2014 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 customer service costs, and all other direct office support expenses.

 

For 2014, these costs increased by approximately $3,241,000 to $6,094,000 compared to $2,853,000 for 2013. The increase was primarily related to $2,500,000 civil penalty resulting from the FERC settlement, and an increase in amortization expense by $326,000 to $697,000 from $371,000 due to the amortization of certain intangible assets acquired in connection with the DEG acquisition. In addition, DEG incurred an additional $150,000 of general and administrative expenses in the period that were not present in 2013. Finally, the Company incurred an additional $271,000 in additional marketing and administrative expenses associated with the Notes Offering in 2014.

 

 

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, 2014, trading tools and subscriptions expense increased by $410,000 or 44.4% to $1,333,000 compared to $923,000 for 2013, primarily due to the acquisition of DEG and the increase in the number of traders.

 

Other income (expense): Other expense, net of other income, increased by $1,191,000 to $2,660,000 for 2014 compared to $1,469,000 for 2013. As the principal component of other expense, interest expense increased by $791,000 to $2,293,000 for the year from $1,502,000 during 2013, primarily due to an increase of $9,103,000 in outstanding debt from $10,185,000 at December 31, 2013 to $19,288,000 at December 31, 2014.

 

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

 

Preferred distributions: During 2014 and 2013, we distributed $549,000 to our preferred unit holder.

 

Liquidity, Capital Resources, and Cash Flow

 

In our wholesale trading business, we require a significant amount of cash to pledge as collateral to market operators which allows us to trade and generate revenues. With respect to our retail operation, in addition to collateral posted with 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 largely to computer and office equipment, software, and office furniture. Therefore, in any given reporting period, the amount of cash consumed or generated will primarily be due to changes in working capital.

 

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

 

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

 

The decision to make distributions other than tax distributions to holders of our common units and required distributions to holders of preferred units is at the discretion of our Board 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 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.

 

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

 

		At December 31,
Dollars in thousands		2014								2013								Increase (decrease)
		Dollars					Percent of total assets			Dollars					Percent of total assets			Dollars					Percent
Liquidity
Cash - unrestricted		$	2,397				7.5%			$	3,190				18.2%			$	(793	)			-24.9%
Cash in trading accounts			20,987				66.1%				10,484				59.7%				10,503				100.2%
Accounts receivable - trade			2,394				7.5%				1,316				7.5%				1,078				81.9%
Total liquid assets			25,778				81.1%				14,990				85.4%				10,788				72.0%
Total assets		$	31,770				100.0%			$	17,562				100.0%				14,208				80.9%
Capital Resources
Current debt		$	8,652				27.2%			$	5,123				29.2%			$	3,529				68.9%
Long term debt			10,636				33.5%				5,062				28.8%				5,574				110.1%
Total debt			19,288				60.7%				10,185				58.0%				9,103				89.4%
Preferred equity			2,745				8.6%				2,745				15.6%				–				0.0%
Common equity			(47	)			-0.1%				2,003				11.4%				(2,050	)			-102.3%
Total equity			2,698				8.5%				4,748				27.0%				(2,050	)			-43.2%
Total capitalization		$	21,986				69.2%			$	14,933				85.0%			$	7,053				47.2%

  

 

The table below summarizes our primary sources and uses of cash for the years ended December 31, 2014 and 2013 as derived from the statements of cash flows included in this Form 10-K.

 

			Years Ended December 31,
Dollars in thousands											Increase (decrease)
			2014				2013				Dollars				Percent
Net cash provided by (used in):
Operating activities		$	53			$	4,350			$	(4,297	)			-98.8	%
Investing activities			(3,515	)			(1,310	)			(2,205	)			168.3	%
Financing activities			3,009				(386	)			3,395				779.5	%
Net cash flow			(453	)			2,654				(3,107	)			-117.1	%
Effect of exchange rate changes on cash			(341	)			(236	)			(105	)			44.5	%
Cash - unrestricted:
Beginning of period			3,190				772				2,418				313.2	%
End of period		$	2,397			$	3,190			$	(794	)			-24.9	%

 

For the year ended December 31, 2014, we generated $53,000 from operating activities. The largest sources of cash from operations was net income of $3,779,000, which included a non-cash change of $3,607,000 related to the FERC settlement, and an increase in accrued compensation of $3,302,000. The most significant items affecting our operating cash flow was a $10,528,000 increase in cash in trading accounts due to increased collateral requirements for both our wholesale and retail businesses. Growth in accounts receivable also used $1,079,000 of cash.

 

During 2014, we used $3,515,000 of cash for investing activities. Our investment in Ultra Green’s convertible notes consumed $1,605,000, we increased our restricted cash balance by $999,000 to secure our position with the Canadian court in conjunction with the former employee litigation (see “Item 8. Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements, Note 19 - Commitments and Contingencies – Former Employee Litigation”), and  the purchase of DEG used $680,000.

 

At December 31, 2014, our debt totaled $19,288,000 compared to $10,185,000 as of the prior year end. For the year, the Company generated $3,009,000 from financing activities, including a net $9,103,000 increase in debt and payment of $5,276,000 in distributions.  Of the total distribution amount, $549,000 was paid to the holder of our preferred units and $4,727,000 was paid to our common unit-holders. 

 

For the year ended December 31, 2013, we generated $4,350,000 from operating activities. The largest sources of cash from operations were net income of $2,131,000 and a decrease in deposits in trading accounts of $2,014,000, while the largest use was a decrease in accrued compensation. During 2013, we used $1,310,000 of cash for investing activities, with the two largest expenditures being for the purchase of the Fox Meadows mortgage for $354,000 and an increase in restricted cash associated with the project of $320,000 to secure a letter of credit. At December 31, 2013, our debt totaled $10,185,000 compared to $6,280,000 as of the prior year end. For the year, the Company used $386,000 for financing activities, including a net increase in debt of $3,655,000 and payment 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.

 

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 the offer and sale of our Renewable Unsecured Subordinated Notes (File No. 333-179460) was declared effective by the SEC, and the 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, 2014 and 2013, we incurred $1,396,000 and $1,113,000, 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 25, 2015, we have sold a total of $22,420,020 in principal amount of Notes and repaid $2,819,796, for a net raise to date of $19,600,224.

 

On May 12, 2014, the Company drew $700,000 under an evergreen, uncommitted line of credit from Royal Bank of Canada (the “RBC Line” and “RBC”, respectively). Advances under the RBC Line bear interest at a variable annual interest rate of 1 month LIBOR plus 2.25% set at the time of advance for a 30 day term, mature at various dates, and are collateralized by assets held in the Company’s marketable securities account. RBC is not obligated to make any extensions of credit to the Company and availability of funds may be increased or decreased by RBC in its sole and absolute discretion. Prepayment of any outstanding principal under the RBC Line may subject the Company to LIBOR break funding costs. There were no borrowings outstanding under the RBC Line as of December 31, 2014.

 

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

 

On October 14, 2014, REH, TSE, and DEG entered into a Credit Agreement with the Toronto, Ontario branch of Maple Bank GmbH (the “Maple Agreement” and “Maple Bank”), expiring October 31, 2016. The Maple Agreement provides the Company’s retail energy services businesses with a revolving line of credit of up to $5,000,000 in committed amount secured by a first position security interest in all of the assets of REH and its subsidiaries, a pledge of the equity of such businesses by TCPH, and certain validity and financial guarantees. Availability of loans is keyed to advance rates against eligible receivables as defined. Any loans outstanding bear interest at an annual rate equal to 3 month LIBOR, subject to a floor of 0.50%, plus a margin of 6.00%. In addition, the Company is obligated to pay an annual fee of 1.00% of the committed amount on a monthly basis and a monthly non-use fee of 1.00% of the difference between the committed amount and the average daily principal balance of any outstanding loans. The Company is also subject to certain customary reporting, affirmative, and negative covenants. As of December 31, 2014, $1,105,000 was outstanding under the Maple Agreement.

 

On November 21, 2014, American Land and Capital, LLC (“American Land”) and Cyclone entered into four construction loan agreements, each for a committed amount of $205,000 or $820,000 in total (the “Fox Meadows Construction Loans”). Each commitment is secured by a mortgage on a lot (numbers 1, 2, 3, and 4) in Block 1 of Fox Meadows 3^rd Addition and is also personally guaranteed by Mr. Krieger. Fox Meadows is a townhouse development located in Lakeville, Minnesota in which Cyclone owns 35 attached residential building sites. Proceeds of the Construction Loans will be used to construct the first four spec/model homes on Cyclone’s Fox Meadows property. Draws on the Construction Loans bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10^th and the notes mature on May 21, 2015. The loans may be prepaid in whole or in part at any time without penalty. As of December 31, 2014, $185,000 was outstanding under the Fox Meadows Construction Loans.

 

 

On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon Holdings, LLC (“Kenyon”), a related party, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a $120,000 note secured by a mortgage on the property and owed to Lakeview Bank (the “Lakeview Bank Mortgage”). Kenyon is owned by Timothy S. Krieger, the Company’s primary owner and its Chief Executive Officer, and Keith W. Sperbeck, its Vice President of Operations. The Lakeview Bank Mortgage bears interest at the highest prime rate reported as such from time to time by The Wall Street Journal. Interest only is payable monthly on the 25^th and the note matures on April 30, 2015. The loan may be prepaid in whole or in part at any time without penalty.

 

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

 

Non-GAAP Financial Measures

 

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

 

Non-GAAP financial measures utilized by the Company 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, including estimates of unbilled revenues for power consumed by customers but not yet billed under the cycle billing method, is recorded in the period in which customers consume the commodity, net of any applicable sales tax.

 

 

Hedge Accounting

 

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

 

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

 

Fair Value Measurements

 

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

 

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

 

Real Estate Development

 

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

 

 

Profits Interest Payments

 

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, 2014 and 2013, we recorded $6,363,520 and $4,300,561, 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, 2014 and 2013 was $801,442 and $169,798, 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 in over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.

 

In our wholesale trading businesses, we measure the risk of our portfolio using several analytical methods, including position limits, stop loss, stress testing, and value-at-risk (“VaR”).

 

Our daily long term VaR model is based upon log-normal returns calculated from the last 30 business days of prices at the 95% confidence level, or 1.645 standard deviations, with a one day liquidity assumption. Our short term VaR model measures the risk of virtual and up-to-congestion transactions and is based upon 4 years of seasonal prices at the 95% confidence level, with a one day liquidity assumption.

 

VaR is calculated daily, using positions and prices updated to the close of business on the previous day. The price history used is ideally that of the instrument held; however, in 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.

 

The VaR model we apply to FTRs (“illiquid VaR”) is based upon 5 years of seasonal prices at the 95% confidence level but with no liquidity assumption, that is, we will not be able to exit the position prior to its maturity due to a lack of trading activity in the instruments. As of December 31, 2014, the longest tenor of our FTR positions was 5 months. As a result of this liquidity assumption, the VaR of our FTRs may not be added to that of our other positions.

 

 

The following table summarizes our liquid and illiquid VaR as of and for the years ended December 31, 2014, and 2013:

 

											Increase (decrease)
			2014				2013				Dollars				Percent
Liquid VaR
As of December 31		$	164,772			$	265,201			$	(100,429	)			-37.9
For the year ended December 31:
Average		$	384,094			$	232,729			$	151,365				65.0
Maximum			1,470,187				1,076,618				393,569				36.6
Minimum			7,453				5,985				1,468				24.5
VaR, pct of cash in trading accounts
As of December 31			0.79%				2.53%				-1.74%				-69.0%
For the year ended December 31:
Average (1)			2.44%				2.07%				0.37%				18.0%
Maximum (1)			9.34%				9.57%				-0.22%				-2.3%
Minimum (1)			0.05%				0.05%				-0.01%				-10.9%
Illiquid VaR
As of December 31		$	3,951,414				na				na				na
For the year ended December 31:
Average			na				na				na				na
Maximum			na				na				na				na
Minimum			na				na				na				na
VaR, pct of cash in trading accounts
As of December 31			18.83%				na				na				na
For the year ended December 31:
Average (1)			na				na				na				na
Maximum (1)			na				na				na				na
Minimum (1)			na				na				na				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 (“MTM”) valuation of these contracts. For example, assuming that all other variables remain constant:

 

					Average percentage change in mark-to-market valuation(1)												Dollar change in mark-to-market valuation(1)
	Percentage change in forward price from December 31, 2014				Derivatives held for trading				Economic hedges				Cash flow hedges				Derivatives held for trading				Economic hedges				Cash flow hedges
	10%				246.2%				41.5%				27.8%				341,331				143,076				239,933
	5%				123.1%				20.7%				13.9%				170,665				71,538				119,967
	1%				24.6%				4.1%				2.8%				34,133				14,308				23,993
	-1%				-24.6%				-4.1%				-2.8%				(34,133	)			(14,308	)			(23,993	)
	-5%				-123.1%				-20.7%				-13.9%				(170,665	)			(71,538	)			(119,967	)
	-10%				-246.2%				-41.5%				-27.8%				(341,331	)			(143,076	)			(239,933	)

______________

(1)    Table includes only liquid positions

 

Interest Rate Risk

 

As of December 31, 2014, we had $1,634,778 of variable rate debt outstanding and at December 31, 2013, we had no such debt outstanding. The interest rates charged on such are based in part on changes in certain market indices plus a credit margin, but are subject to “floors”, which may have the effect of converting variable rates to fixed rates and such was the case at December 31, 2014. Consequently, at either date, we had no variable rate debt, although in the future we may be exposed to fluctuations in interest rates. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars, and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument.

 

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% change in electricity prices would cause an increase in margin collateral posted of approximately $1,448,680 and $438,000 as of December 31, 2014 and 2013, respectively. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of the dates indicated.

 

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.

 

In our wholesale trading business, we monitor and manage credit risk through the credit policies described in “Item 1 - Business – Wholesale Trading – Credit Risk Management” and 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.

 

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

 

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.

 

 

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 criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO). Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2014.

 

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.

 

 

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, 2014 and 2013, 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, 2014 and 2013, 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 27, 2015

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Balance Sheets

As of December 31, 2014 and 2013

 

		2014				2013
Assets
Current assets
Cash - unrestricted		$	2,397,300			$	3,190,495
Cash in trading accounts			20,987,152				10,484,448
Accounts receivable - trade			2,394,246				1,315,209
Note receivable			–				140,964
Marketable securities			311,586				256,004
Prepaid expenses and other current assets			528,919				242,482
Total current assets			26,619,203				15,629,602
Property, equipment, and furniture, net			762,529				504,298
Other assets
Intangible assets, net			269,149				305,978
Deferred financing costs, net			241,744				337,559
Cash - restricted			1,319,371				320,188
Land held for development			953,462				110,477
Mortgage note receivable			–				353,504
Investment in convertible notes			1,604,879				–
Total assets		$	31,770,337			$	17,561,606
Liabilities and Members' Equity
Current liabilities
Current portions of debt
Revolver		$	1,105,259			$	–
Senior notes			312,068				200,000
Renewable unsecured subordinated notes			7,234,559				4,922,596
Accounts payable - trade			1,544,103				1,035,644
Accrued expenses			681,995				683,556
Accrued compensation			3,601,282				299,439
Accrued interest			849,913				359,758
Obligations under non-competition agreement			–				250,000
Obligations under settlement agreement			582,565				–
Total current liabilities			15,911,744				7,750,993
Long-term liabilities
Senior notes			217,451				–
Obligations under settlement agreement			2,524,448				–
Renewable unsecured subordinated notes			10,418,569				5,062,230
Total liabilities			29,072,212				12,813,223
Commitments and contingencies
Members' equity
Series A preferred equity			2,745,000				2,745,000
Common equity			(193,624	)			1,302,994
Accumulated other comprehensive income			146,749				700,389
Total members' equity			2,698,125				4,748,383
Total liabilities and members' equity		$	31,770,337			$	17,561,606

 

See notes to consolidated financial statements.

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Comprehensive Income

For the Years Ended December 31, 2014 and 2013

 

		2014				2013
Revenue
Wholesale trading revenue, net		$	38,611,944			$	25,305,723
Retail electricity revenue			11,229,476				7,479,775
			49,841,420				32,785,498
Costs and expenses
Cost of retail electricity sold			11,440,672				7,760,674
Retail sales and marketing			324,948				493
Compensation and benefits			21,722,319				15,965,063
Professional fees			2,487,056				1,673,454
Other general and administrative			6,093,843				2,853,517
Trading tools and subscriptions			1,332,804				922,756
			43,401,642				29,175,957
Operating income			6,439,778				3,609,541
Other income (expense)
Interest expense			(2,293,376	)			(1,501,935	)
Interest income			142,915				30,272
Gain (loss) on foreign currency exchange			(720,952	)			2,261
Realized gain on sale of marketable securities			65,655				–
Other income			145,164				–
			(2,660,594	)			(1,469,402	)
Income before income taxes			3,779,184				2,140,139
Income tax provision			–				8,823
Net income			3,779,184				2,131,316
Distributions - preferred			(549,072	)			(549,036	)
Net income attributable to common			3,230,112				1,582,280
Other comprehensive income (loss)
Foreign currency translation adjustment			661,033				(201,303	)
Change in fair value of cash flow hedges			(1,220,022	)			438,646
Unrealized gain on investment securities			5,349				5,767
Comprehensive income		$	3,225,544			$	2,374,426

 

See notes to consolidated financial statements.

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2014 and 2013

 

		2014				2013
Cash flows from operating activities
Net income		$	3,779,184			$	2,131,316
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			869,631				557,035
Gain on sale of marketable securities			(65,655	)			–
Loss on sale of property, equipment, and furniture			–				14,802
Loss on settlement agreement			3,607,013				–
(Increase) decrease in:
Trading accounts and deposits			(10,528,239	)			2,013,968
Accounts and notes receivable			(1,079,036	)			876,059
Prepaid expenses and other assets			(183,638	)			(52,674	)
Increase (decrease) in:
Accounts payable - trade			508,459				(433,664	)
Accrued expenses			(145,870	)			613,178
Accrued compensation			3,301,843				(1,684,949	)
Accrued interest			490,155				315,286
Obligations under settlement agreement			(500,000	)			–
Net cash provided by operating activities			53,847				4,350,357
Cash flows from investing activities
Purchase of marketable securities			(1,214,004	)			(250,237	)
Proceeds from sale of marketable securities			1,229,426				–
Purchase of convertible notes			(1,604,879	)			–
(Advance) repayment of note receivable			140,964				(140,964	)
Purchase of property, equipment, and furniture			(202,759	)			(134,135	)
Purchase of land held for development			(184,529	)			(110,477	)
Purchase of mortgage note receivable			–				(353,504	)
Advance of restricted cash			(999,183	)			(320,188	)
Acquisition of Discount Energy Group, LLC			(680,017	)			–
Net cash used in investing activities			(3,514,981	)			(1,309,505	)
Cash flows from financing activities
Deferred financing costs			(35,000	)			–
Proceeds from line of credit			700,000				–
Payments on line of credit			(700,000	)			–
Payments on senior notes			(203,433	)			(4,066,927	)
Proceeds from revolver			1,850,000				–
Payments on revolver			(744,741	)			–
Proceeds from renewable unsecured subordinated notes			9,308,708				8,625,775
Redemptions of renewable unsecured subordinated notes			(1,640,406	)			(654,087	)
Payment of obligations under non-competition agreement			(250,000	)			(250,000	)
Distributions - preferred			(549,072	)			(549,036	)
Distributions - common			(4,726,730	)			(3,491,890	)
Net cash from (used in) financing activities			3,009,326				(386,165	)
Net increase (decrease) in cash			(451,808	)			2,654,687
Effect of exchange rate changes on cash			(341,387	)			(236,044	)
Cash - unrestricted
Beginning of year			3,190,495				771,852
End of year		$	2,397,300			$	3,190,495

 

See notes to consolidated financial statements.

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Cash Flows (Continued)

For the Years Ended December, 31 2014 and 2013

 

		2014				2013
Non-cash investing and financing activities:
Effective portion of cash flow hedges		$	(863,408	)		$	356,614
Obligations under non-competition agreement		$	–			$	500,000
Series A preferred units issued in exchange for redeemable preferred units		$	–			$	2,745,000
Acquisition of land for development via foreclosure on mortgage loan		$	353,504			$	–
Acquisition of land for development via assignment and assumption agreement		$	304,952			$	–
Unrealized gain on marketable securities		$	11,116			$	5,767
Supplemental disclosures of cash flow information:
Cash payments for interest		$	1,793,221			$	1,186,649
Cash payments for income taxes, net		$	–			$	8,823

 

See notes to consolidated financial statements.

 

 

Twin Cities Power Holdings, LLC and Subsidiaries

 

Consolidated Statements of Changes in Members’ Equity

For the Years ended December 31, 2014 and 2013

 

		Series A Preferred Equity				Common Equity				Accumulated Other Comprehensive Income				Total
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
Net income			–				3,779,184				–				3,779,184
															–
Other comprehensive loss			–				–				(553,640	)			(553,640	)
															–
Distributions - preferred			–				(549,072	)			–				(549,072	)
															–
Distributions - common			–				(4,726,730	)			–				(4,726,730	)
Balance - December 31, 2014		$	2,745,000			$	(193,624	)		$	146,749			$	2,698,125

 

See notes to consolidated financial statements.

 

 

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, in 2013 the Company entered the residential real estate development business, and in 2014, the Company made additional investments in its diversified investments segment. Consequently, the Company has three business segments used to measure its activity – wholesale trading, retail energy services, and diversified investments.

 

On October 27, 2014, the Company formed Apollo Energy Services, LLC (“Apollo”) as a wholly-owned subsidiary for the purpose of providing centralized services to the Company’s various other subsidiaries. Substantially all of the management rights and certain of the direct employees of TCPH were transferred to Apollo as of January 1, 2015.

 

The Operating Companies

 

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

·

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, is currently active, 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.

·

Minotaur Energy Futures, LLC (“MEF”) was formed on March 25, 2014 and is currently active.

 

 

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 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.

 

During the year ended December 31, 2014, TCPC was inactive. During the year ended December 31, 2013 the entity 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.

 

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.

 

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 Equivalents

 

Cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. As of December 31, 2014 and 2013, the Company had no cash equivalents.

 

Reclassifications

 

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

 

Revenue Recognition

 

Wholesale Trading

 

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

 

Retail Energy Services

 

Revenue from the retail sale of electricity to customers is recorded in the period in which the commodity is consumed, net of any applicable sales tax. The Company follows the accrual method of accounting for revenues whereby electricity consumed by customers but not yet billed under the cycle billing method is estimated and accrued along with the related costs. Changes in estimates are reflected in operations in the period in which they are refined. During the years ended December 31, 2014 and 2013, the Company recorded additional retail sales of electricity of $465,000 and $0, respectively, due to a change in the amount of estimated unbilled revenue.

 

Diversified Investments

 

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

 

 

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 losses of $720,952 and $2,261 for the years ended December 31, 2014 and 2013, 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 concentrations 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, 2014 and 2013 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, 2014 and 2013 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

 

Receivables are reported at the amount management expects to collect from outstanding balances. Differences between amounts due and expected collections are reported in the results of operations for the period in which those differences are determined. Receivables are written off only after collection efforts have failed, and the Company typically does not charge interest on past due accounts. There was no allowance for doubtful accounts as of December 31, 2014 or 2013.

 

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” or “AOCI”. 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.

 

Property, Equipment, and Furniture

 

Property, 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. Property is depreciated using the straight-line method over the estimated useful life of 27.5 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, 2014 and 2013, the Company included $6,363,520 and $4,300,561, 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 2011 through 2014 and its Canadian tax returns are potentially open to examination for the years 2011 through 2014.

 

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 (“CRA”) 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. On April 22, 2014, a letter from the CRA was received noting that an adjustment was made to our account.

 

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

 

New Accounting Pronouncements

 

In May 2014, the FASB issued new accounting guidance related to revenue recognition. This new standard will eliminate all industry-specific guidance and replace all current U.S. GAAP guidance on the topic. The new revenue recognition standard provides a unified model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration for which the entity expects to be entitled in exchange for those goods or services. This guidance will be effective for the Company beginning January 1, 2017 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the impact on the Company’s consolidated 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. The adoption of the standard on January 1, 2014 did not have a material impact on the Company’s 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, 2014 and 2013 was $1,319,371 and $320,188, respectively. At December 31, 2014, all restricted cash was posted as security in connection with certain litigation in the Canadian courts. See “Note 19 - Commitments and Contingencies”.

 

Cash held in trading accounts may be unavailable at times for immediate withdrawal depending upon trading activity. Cash needed to meet credit requirements for outstanding trades and that was available for immediate withdrawal as of December 31, 2014 and 2013 was as follows:

 

		December 31,				December 31,
		2014				2013
Credit requirement		$	4,817,881			$	2,185,175
Available credit			16,169,271				8,299,273
Cash in trading accounts		$	20,987,152			$	10,484,448

 

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, 2014 and 2013:

 

		Fair Value
		Asset Derivatives				Liability Derivatives
At December 31, 2014
Designated as cash flow hedges:
Energy commodity contracts		$	15,732			$	(879,140	)
Not designated as hedging instruments:
Energy commodity contracts			2,350,662				(2,556,862	)
FTRs, net			1,435,819				–
Total derivative instruments			3,802,213				(3,436,002	)
Cash deposits in collateral accounts			20,620,941				–
Cash in trading accounts, net		$	24,423,154			$	(3,436,002	)
At December 31, 2013
Designated as cash flow hedges:
Energy commodity contracts		$	417,309			$	(60,695	)
Not designated as hedging instruments:
Energy commodity contracts			717,606				(757,828	)
Total derivative instruments			1,134,915				(818,523	)
Cash deposits in collateral accounts			10,168,056				–
Cash in trading accounts, net		$	11,302,971			$	(818,523	)

 

 

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

 

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 net gain on the effective portion of the hedge was deferred and included in AOCI. This entire amount was 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, 2014
Cash flow hedges		$	(1,128,514	)		Cost of energy sold		$	91,508
Year Ended December 31, 2013
Cash flow hedges		$	685,936			Cost of energy sold		$	247,290

 

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, 2013 to December 31, 2014:

 

		Foreign Currency				Cash Flow Hedges				Available for Sale Securities				Total
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
Other comprehensive income (loss) before reclassifications			661,033				(1,128,514	)			11,116			$	(456,365	)
Amounts reclassified from AOCI			–				(91,508	)			(5,767	)			(97,275	)
Net current period other comprehensive income (loss)			661,033				(1,220,022	)			5,349				(553,640	)
Balance - December 31, 2014		$	999,041			$	(863,408	)		$	11,116			$	146,749

 

 

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,
		2014				2013
Wholesale trading		$	515,999			$	168,953
Retail energy services - billed			1,158,019				944,100
Retail energy services - unbilled			720,228				202,156
Accounts receivable - trade		$	2,394,246			$	1,315,209

 

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

 

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. 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 bore interest at 8.00% and was 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.

 

7.

Marketable Securities

 

The following table shows the cost and estimated fair value of available-for-sale securities at December 31, 2014 and 2013:

 

		Cost				Gross Unrealized Gains				Gross Unrealized Losses				Fair Value
At December 31, 2014
U.S. equities		$	299,836			$	11,116			$	–			$	310,952
Money market fund			634				–				–				634
Total		$	300,470			$	11,116			$	–			$	311,586
At December 31, 2013
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

 

For the years ended December 31, 2014 and 2013, the Company had sales of securities and realized a gain of $65,655 and zero, respectively, and recognized no impairment charges.

 

 

The following table shows the gross unrealized losses on, and fair value of, securities positions by the length of time such assets were in a continuous loss position as of December 31, 2014 and 2013:

 

			Less than Twelve Months
			Gross Unrealized Losses				Fair Value
At December 31, 2014
International equities		$	–			$	–
At December 31, 2013
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.

 

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

 

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

 

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

 

There have been no changes in the methodologies used since December 31, 2013.

 

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, 2014
Cash in trading accounts, net		$	19,551,333			$	–			$	–			$	19,551,333
FTR positions, net			–				–				1,435,819				1,435,819
Marketable securities			311,586				–				–				311,586
Investment in convertible notes			–				–				1,604,879				1,604,879
December 31, 2013
Cash in trading accounts, net		$	10,484,448			$	–			$	–			$	10,484,448
Marketable securities			256,004				–				–				256,004
Mortgage note receivable			–				–				353,504				353,504

 

 

There were no transfers during the year ended December 31, 2014 between Levels 1 and 2.

 

Level 3 Assets

 

The following table reconciles beginning and ending Level 3 fair value financial instrument balances for the years ended December 31, 2014 and 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
Transfers into Level 3			–
Transfers out of Level 3			–
Balance - December 31, 2013			353,504
Total gains and losses:
Included in other comprehensive income			–
Included in earnings			1,435,819
Purchases			1,604,879
Transfers into Level 3			–
Transfers out of Level 3*			(353,504	)
Balance - December 31, 2014		$	3,040,698
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, 2014		$	1,435,819

 

___________________

* - Reflects foreclosure on mortgage note and transfer of land received to "Land held for development"; see "Note 12 - Land Held for Development; Mortgage Receivable".

 

Valuation Techniques and Sensitivity of Level 3 Fair Values

 

The following table describes the valuation techniques used to measure the fair value of the Company’s Level 3 assets at December 31, 2014.

 

Type of Level 3 Asset	Fair Value at December 31, 2014	Valuation Techniques	Unobservable Inputs	Range of Inputs
FTRs	$          1,435,819	Mark-to-model	Forward congestion prices	$(7.35) to $24.18 per MWh
Investment in  convertible notes	$          1,604,879	Private equity component: Discounted cash flow and market multiples for both comparable publicly traded companies and merger and acquisition transactions	Future cash flows	various
			Component costs of capital	6.92 to 12.80% for debt, 19.15% for equity
			Target capital structure	33% debt, 67% equity
			Marginal tax rate	40%
			Weighted average cost of capital	14.47%
			Price/sales ratio	0.71x to 3.80x
			Price/earnings ratio	17.08x to 49.19x
			Price/cash flow ratio	7.36x to 14.32x
			Price/assets ratio	1.69x
			Price/book ratio	1.37x to 3.23x
			Price/EBITDA ratio	6.48x
		Debt component: Comparable credits	Credit margins	3.00% to 10.27%
			Deferred financing costs	2.00% to 4.00%
		Embedded option: Black-Scholes option valuation model	Current stock price	$0.00 to $0.01/share
			Option exercise price	$0.01/share
			Risk-free rate	0.10%
			Stock price volatility	100%
			Time to expiration	5 years

 

 

Changes in the inputs listed above would have a direct impact on the fair values of the above instruments. For example, the significant unobservable input used in the fair value measurement of the FTRs is the price of forward congestion. Increases or decreases in the market price proxy values assumed would result in significantly higher or lower fair values. Further, an increase or decrease in the estimated current price of the embedded option incorporated into the convertible notes would increase or decrease the fair value of the investment.

 

Financial Transmission Rights

 

FTRs are derivative financial instruments that entitle the holder to a stream of revenues, or require them to pay charges, based on the differences in day-ahead market marginal congestion cost (“MCC”) across transmission paths. FTRs are specified by a source (the start of the transmission path), a sink (the end of the path), a time period measured in hours, and a number of megawatts. FTRs may be acquired by us in monthly, annual, or long term auctions conducted by certain ISOs and are initially recorded using the auction clearing price less cost, that is, zero.

 

After initial recognition, the carrying values of FTRs are periodically adjusted to fair value using a mark-to-model methodology, which we believe approximates market. Note that there is generally not a liquid market for FTRs. Our FTR valuation model is:

 

Fair Value = (Market Price Proxy - Trade Price) x Volume x Funding Discount

Where:

·

Market Price Proxy (in $/MWh) = 30 day average of the hourly MCC at the source minus the hourly MCC at the sink;

·

Trade Price (in $/MWh) = the price paid for the FTR;

·

Volume (in MWh) = remaining volume of the position;

·

Funding Discount (a percentage) = the lowest level of funding of FTRs by the ISO in the last 12 months, applied only to the total positive fair value across all positions, not to an individual transaction.

 

Investment in Convertible Notes

 

As of December 31, 2014, the Company had an investment of $1,604,879 (principal and accrued interest of $1,500,000 and $104,879, respectively) in the Series C Convertible Promissory Notes of Ultra Green Packaging, Inc. (the “C Notes” and “Ultra Green”, respectively). See also “Note 13 – Convertible Promissory Note” for additional information.

 

As no public market exists for any of the securities of Ultra Green, including its C Notes, management considers its investment to be a Level 3 financial instrument to be carried at book value which management believes approximates fair value, until circumstances otherwise dictate. Each quarter, management performs a valuation of the underlying common equity and the security using generally accepted methods to value the obligations of private companies to determine if impairment to its carrying value exists.

 

9.

Property, Equipment and Furniture

 

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

 

		2014				2013
Equipment and software		$	857,952			$	735,326
Furniture			304,791				291,958
Land			150,000				–
Building			137,958				–
Leasehold improvements			197,102				192,561
Property, equipment and furniture, gross			1,647,803				1,219,845
Less: accumulated depreciation			(885,274	)			(715,547	)
Property, equipment and furniture, net		$	762,529			$	504,298

 

Depreciation expense was $169,727 and $186,267 for the years ended December 31, 2014 and 2013, 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 with David B. Johnson, a current governor of the Company valued at $500,000, to be amortized and paid in equal installments over 24 months.

 

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

 

		December 31,				December 31,
		2014				2013
Other intangibles		$	714,658			$	160,000
Non-competition agreement			500,000				500,000
Less: accumulated amortization			(945,509	)			(354,022	)
Intangible assets, net		$	269,149			$	305,978

 

Total amortization of intangible assets for the years ended December 31, 2014 and 2013 was $591,487 and $319,348, 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,
		2014				2013
Deferred financing costs		$	428,990			$	393,990
Less: accumulated amortization			(187,246	)			(56,431	)
Deferred financing costs		$	241,744			$	337,559

 

Total amortization of deferred financing costs for the year ended December 31, 2014 and 2013 was $130,815 and $51,420, respectively and is included in other general and administrative expenses.

 

  

12.

Land Held for Development; Mortgage Receivable

 

On December 18, 2013, the Company bought a defaulted note secured by a first mortgage on certain real property from Bremer Bank, National Association with the intention of foreclosing and thereby obtaining title to the land. As of December 31, 2013, land held for development totaled $110,477, consisting of one single family lot. Also as of the same date, the carrying value of the mortgage totaled $353,504 and consisted of the purchase price of $340,000 of principal and $13,504 of accrued interest. On April 21, 2014, the foreclosure on the mortgage note was completed. Consequently, the note was cancelled and the land received was reclassified to “land held for development” and as of December 31, 2014, land held for development totaled $953,462.

 

13.

Convertible Promissory Note

 

On March 20, 2014, the Company invested $1,000,000 in a privately placed Convertible Promissory Note (the “B Note”) issued by Ultra Green Packaging, Inc. (“Ultra Green”). On each of June 4 and June 18, 2014, the Company loaned Ultra Green $50,000, for a total of $100,000, in the form of short term, unsecured promissory notes (the “Short Term Notes”), each with a maturity date of July 31, 2014. On July 2, 2014, the Company invested $400,000 in C Notes as described below. Effective as of the same date, the principal of the Short Term Notes was also converted into C Notes, and on November 10, 2014, the Company converted its B Notes to C Notes. As of December 31, 2014, the principal amount of, and accrued interest on, the C Notes owned by the Company was $1,500,000 and $104,879, respectively for a total of $1,604,879.

 

Ultra Green develops, manufactures, and markets “ecopaper” products made from wheat straw, bamboo, or sugarcane fibers and bioplastic products made from cornstarch. Ultra Green’s ecopaper and bioplastic products are certified as biodegradable and sustainable, and are compostable in about 160 days. Ultra Green is privately held and was not profitable for the year ended December 31, 2014.

 

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

 

On June 19, 2014, the Board of Directors of Ultra Green authorized an offering of Convertible Promissory Notes convertible into Series C Preferred Stock, the terms of which are more fully described below (the “C Notes” and “Series C Preferred”, respectively). The C Notes will mature on December 31, 2019 and bear interest at a fixed rate of 10% per annum. Interest will accrue until June 30, 2015, at which time all accrued and unpaid interest will become due and payable. Thereafter, interest will be due and payable on a quarterly basis.

 

The outstanding principal and accrued interest on the C Notes may be converted into shares of Ultra Green’s Series C Preferred Stock on their maturity date at the option of the Company at an initial conversion price of $1.00 per share, as adjusted. In addition, at any time prior to or at maturity and upon the affirmative vote of the holders of 66.625% of the aggregate outstanding principal amount of the C Notes, all of the C Notes will convert into shares of Series C at the conversion price of $1.00 per share. The Series C shall have voting rights on an “as-converted” basis, voting with the common stock on any matter presented to the shareholders of the Company for their action or consideration at any shareholder meeting, or by written consent in lieu thereof. Finally, each share of Series C is convertible into 100 Ultra Green common shares for an initial conversion price of $0.01 per share.

 

 

The C Note offering closed on November 10, 2014 with $9,155,302 of notes sold. As of December 31, 2014, excluding options and warrants for 5,390,000 shares with exercise prices in excess of $0.50, Ultra Green had 1,119,130,554 fully diluted common and common-equivalent shares outstanding. Assuming no additional issuances of common or common-equivalents to others, conversion of its C Notes into common shares, and the exercise of the option described above, the Company would own 200,000,000 common shares or 17.87% of the fully diluted shares outstanding.

 

14.

Debt

 

Notes payable by the Company are summarized as follows:

 

		December 31, 2014				December 31, 2013
Demand and Revolving Debt
Payable to ABN AMRO		$	–			$	–
Payable to Royal Bank of Canada			–				–
Revolving note payable to Maple Bank			1,105,259				–
Subtotal			1,105,259				–
Term Debt
Note payable to John O. Hanson			–				200,000
Mortgage note payable to Security State Bank			224,568				–
Mortgage note payable to Lakeview Bank			119,976				–
Construction note payable to American Land & Capital			184,975				–
Renewable unsecured subordinated notes			17,653,128				9,984,826
Subtotal			18,182,647				10,184,826
Total		$	19,287,906			$	10,184,826

 

Notes payable by maturity are summarized as follows:

 

		December 31, 2014				December 31, 2013
Demand and Revolving Debt
Demand		$	–			$	–
2016			1,105,259				–
Subtotal			1,105,259				–
Term Debt
2014			–				5,122,596
2015			7,546,627				–
Current maturities			7,546,627				5,122,596
2015			–				1,266,590
2016			2,648,150				772,250
2017			2,869,383				549,140
2018			2,642,972				2,297,250
2019			1,213,227				177,000
2020 & thereafter			1,262,288				–
Long term debt			10,636,020				5,062,230
Subtotal			18,182,647				10,184,826
Total		$	19,287,906			$	10,184,826

 

 

ABN-AMRO Margin Agreement

 

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

 

As of December 31, 2014 and 2013, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants.

 

RBC Line of Credit

 

On May 12, 2014, the Company drew $700,000 under an evergreen, uncommitted line of credit from Royal Bank of Canada (the “RBC Line” and “RBC”, respectively). Advances under the RBC Line bear interest at a variable annual interest rate of 1 month LIBOR plus 2.25% set at the time of advance for a 30 day term, mature at various dates, and are collateralized by assets held in the Company’s marketable securities account. RBC is not obligated to make any extensions of credit to the Company and availability of funds may be increased or decreased by RBC in its sole and absolute discretion. Prepayment of any outstanding principal under the RBC Line may subject the Company to LIBOR break funding costs.

 

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

 

Maple Bank Revolver

 

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

 

As of December 31, 2014, there was $1,105,259 outstanding under the Maple Agreement and the Company was in compliance with all covenants.

 

 

John O. Hanson

 

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. On June 28, 2013, Mr. Hanson sold the redeemable preferred units to Mr. Krieger, and consequently, he was no longer a related party. On March 25, 2014, the Company repaid Mr. Hanson’s $200,000 note in full.

 

Security State Mortgage

 

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

 

As of December 31, 2014, the Company was in compliance with all terms and conditions of the Security State Mortgage.

 

Lakeview Bank Mortgage

 

On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon Holdings, LLC (“Kenyon”), a related party, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a note secured by a mortgage on the property and owed to Lakeview Bank (the “Lakeview Bank Mortgage”). Kenyon is owned by Mr. Krieger and Keith W. Sperbeck, the Company’s Vice President of Operations. The Lakeview Bank Mortgage bears interest at the highest prime rate reported as such from time to time by The Wall Street Journal. Interest only is payable monthly on the 25^th and the note matures on April 30, 2015. The loan may be prepaid in whole or in part at any time without penalty.

 

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

 

American Land and Capital Construction Loans

 

On November 21, 2014, American Land and Capital, LLC (“American Land”) and Cyclone entered into four construction loan agreements, each for a committed amount of $205,000 or $820,000 in total (the “Construction Loans”). Each commitment is secured by a mortgage on a lot (numbers 1, 2, 3, and 4) in Block 1 of Fox Meadows 3^rd Addition and is personally guaranteed by Mr. Krieger. Fox Meadows is a townhouse development located in Lakeville, Minnesota in which Cyclone owns 35 attached residential building sites. Proceeds of the Construction Loans will be used to construct the first four spec/model homes on Cyclone’s Fox Meadows property. Draws on the Construction Loans bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10^th and the notes mature on May 21, 2015. The loans may be prepaid in whole or in part at any time without penalty.

 

 

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

 

Renewable Unsecured Subordinated Notes

 

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

 

The Company made interest payments during the years ended December 31, 2014 and 2013 of $1,304,701 and $443,367, respectively. Total accrued interest on the Subordinated Notes at December 31, 2014 and 2013 was $849,913 and $354,094, respectively.

 

As of December 31, 2014, the Company had $17,653,128 of its Subordinated Notes outstanding as follows:

 

Initial Term		Principal Amount				Weighted Average Interest Rate
3 months		$	486,472				11.06%
6 months			230,450				8.27%
1 year			5,255,047				12.40%
2 years			2,805,332				13.19%
3 years			3,196,847				14.45%
4 years			802,385				14.81%
5 years			3,799,605				15.97%
10 years			1,076,990				14.56%
Total		$	17,653,128				13.82%
Weighted average term			36.5 mos

 

15.

Leases

 

The Company leases vehicles and office equipment under several agreements that expire between 2015 and 2019 as well as its office space, key terms of the leases for which are summarized below.

 

Location		Expiration Date				Square Footage				Monthly Rent
Lakeville, Minnesota*			12	/31/2017			10,730			$	11,113
Cherry Hill, New Jersey			12	/31/2015			175				400
Tulsa, Oklahoma*			2	/28/2016			1,800				3,750
East Windsor, New Jersey			9	/30/2016			1,150				2,374
Newtown, Pennsylvania			12	/31/2017			1,711				2,400
Chandler, Arizona*			7	/31/2019			2,712				4,068
Total							18,278			$	24,105

____________________

* See Note 18. Related Party Transactions

 

 

Total lease expense was $443,193 and $450,069 for the years ended December 31, 2014 and 2013, respectively.

 

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

 

Years Ended December 31,		Amount
2015		$	329,000
2016			277,000
2017			244,000
2018			62,000
2019			34,000
Total		$	946,000

 

16.

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.

 

17.

Ownership

 

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 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.

 

The ownership of the Company’s equity as of December 31, 2014 is as presented below:

 

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

 

 

18.

Related Party Transactions

 

Interest expense associated with notes payable to related parties was $31,550 for the year ended December 31, 2013. There were no notes payable to related parties at December 31, 2014.

 

The building in which the Company leases its Lakeville, Minnesota office space is owned by Kenyon and on January 1, 2013, the Company and Kenyon entered into a five year lease expiring December 31, 2017 for 11,910 square feet at a monthly rent of $12,264. On September 25, 2014, the lease was amended to reduce the square footage to 10,730 and monthly rent to $11,113. For rent, real estate taxes, and operating expenses, the Company paid Kenyon $235,000 and $227,200 for the years ended December 31, 2014 and 2013, respectively.

 

Effective January 1, 2013, in connection with the purchase of David B. Johnson’s units by Mr. Krieger, the Company entered into a non-competition agreement with Mr. Johnson, a current governor and former member of the Company, pursuant to which the Company is obligated to pay Mr. Johnson $500,000 in 24 equal monthly installments of $20,833 each. The total amount paid pursuant to the agreement during the years ended December 31, 2014 and 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, 2014 and 2013 was $45,000 and $41,250, respectively.

 

In connection with the Company’s initial investment of $1.0 million in Ultra Green (see “Note 13 – Convertible Promissory Note”), Ultra Green paid a 10% commission to Cedar Point Capital, LLC, a registered broker dealer (“Cedar Point”). David B. Johnson, a governor of the Company, is the sole owner of Cedar Point. No commissions were paid on the Company’s follow-on investments.

 

On June 17, 2014, the building in which the Company leases its Chandler, Arizona office space occupied by certain of its retail business functions was purchased by Fulton Marketplace, LLC (“Fulton”), a company owned by Mr. Krieger and Mr. Sperbeck. Effective August 1, 2014, the Company and Fulton entered into a five year lease expiring July 31, 2019, subject to two consecutive five year extension periods, for 2,712 square feet. The rent for the first lease year is $4,068 per month and it will increase by 3% annually at the start of each lease year thereafter. The Company paid $26,700 to Fulton for the year ended December 31, 2014 for rent, real estate taxes, and operating expenses.

 

Fulton is the owner of a single family residence in Chandler, Arizona. Effective December 1, 2014, Fulton and REH entered into a seven month lease expiring June 30, 2015 with respect to the property for rent of $2,800 per month.

 

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

 

 

19.

Commitments and Contingencies

 

FERC Settlement

 

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

 

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

 

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

 

Former Employee Litigation

 

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

 

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

 

 

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

 

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

 

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

 

PJM Resettlements

 

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

 

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

 

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

 

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

 

PJM Up To Congestion Fees

 

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

 

 

Currently, under PJM’s Tariff and Operating Agreement, UTCs are treated differently under its FTR forfeiture rule than are INCs and DECs, two other types of virtual transactions. Further, INCs and DECs are subject to uplift charges, but UTCs are not. In Docket No EL14-37-000, FERC noted that should any uplift be charged UTCs, it would apply such back to the date that notice of the proceeding was published in the Federal Register (September 8, 2014), thus setting a “refund effective date”. From the refund effective date to December 31, 2014, the Company traded about 1,750,000 MWh of UTCs in PJM and recorded $807,000 of associated revenues.

 

Although the Company’s UTC trading activity exposes it to potential uplift charges, none have been billed as the investigation is still pending. Further, TCPH has not established any reserves for such as management is uncertain as to the probability, amount, and timing of the actual payment, if any, that might be due.

 

Letter of Credit

 

On June 24, 2014, the Company’s restricted cash balance of $320,188 was returned by the City of Lakeville and a letter of credit in favor of Cyclone was issued by Vermillion State Bank for the same amount. The note evidencing the letter of credit calls for maximum advances of up to $320,188, bears interest at an annual rate of 5.25%, is secured by a mortgage on the property being developed and the guaranty of Cyclone, and matures on demand. As of December 31, 2014 the Company was in compliance with all terms and conditions of the letter of credit.

 

Guarantees

 

In the ordinary course, the Company provides guarantees of the obligations of TCP, SUM, and CEF with respect to their participation in certain ISOs. As of December 31, 2014, such guarantees were in an unlimited amount for PJM, an unlimited amount for NYISO, up to $2,000,000 for MISO, and up to $5,000,000 for ERCOT.

 

On August 12, 2013, the Company entered into a guaranty of the obligations of TSE of up to $1,000,000 (plus any costs of collection or enforcement) in favor of Noble Americas Energy Solutions LLC (“Noble”).

 

On April 25, 2014, the Company entered into a guaranty of the obligations of DEG of up to $1,000,000 (plus any costs of collection or enforcement) in favor of Noble.

 

On November 5, 2014, the Company entered into two separate guaranties of the obligations of TSE and DEG of up to $500,000 (plus any costs of enforcement or collection) in favor of Shell Energy North America L.P.

 

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

 

 

20.

Segment Information

 

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

 

·

Wholesale trading activities earn profits from trading financial, physical, and derivative electricity in wholesale markets regulated by the FERC and the CFTC.

·

On July 1, 2012, the Company began selling electricity to residential and small commercial customers.

·

On October 23, 2013, the Company formed a new entity to take advantage of certain investment opportunities in the residential real estate market and in 2014, it made certain investments in the securities of emerging companies.

 

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, 2014 and 2013, 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, 2014 is as follows:

 

		Wholesale Trading				Retail Energy Services				Diversified Investments				Corporate, Net of Eliminations				Consolidated Total
Year Ended December 31, 2014
Wholesale trading		$	36,894,702			$	1,717,242			$	–			$	–			$	38,611,944
Retail energy services			–				11,229,476				–				–				11,229,476
Revenues, net			36,894,702				12,946,718				–				–				49,841,420
Costs of retail electricity sold			–				11,440,672				–				–				11,440,672
Retail sales and marketing			–				324,948				–				–				324,948
Compensation and benefits			19,196,234				391,931				–				2,134,154				21,722,319
Professional fees			686,643				876,488				2,200				921,725				2,487,056
Other general and administrative			7,720,546				1,314,991				108,938				(3,050,632	)			6,093,843
Trading tools and subscriptions			902,364				386,349				2,765				41,326				1,332,804
Operating costs and expenses			28,505,787				14,735,379				113,903				46,573				43,401,642
Operating income (loss)		$	8,388,915			$	(1,788,661	)		$	(113,903	)		$	(46,573	)		$	6,439,778
Capital expenditures		$	15,773			$	738,615			$	185,529			$	127,388			$	1,067,305
At December 31, 2014
Identifiable Assets
Cash - unrestricted		$	1,296,294			$	288,436			$	5,925			$	806,645			$	2,397,300
Cash in trading accounts			19,642,215				1,344,937				–				–				20,987,152
Accounts receivable - trade			501,182				1,878,247				–				14,817				2,394,246
Marketable securities			–				–				–				311,586				311,586
Prepaid expenses and other assets			127,209				159,543				30,943				211,224				528,919
Total current assets			21,566,900				3,671,163				36,868				1,344,272				26,619,203
Property, equipment and furniture, net			80,048				99,068				1,000				582,413				762,529
Intangible assets, net			–				269,149				–				–				269,149
Deferred financing costs, net			–				31,354				–				210,390				241,744
Cash - restricted			1,319,371				–				–				–				1,319,371
Land held for development			–				–				953,462				–				953,462
Investment in convertible notes			–				–				1,604,879				–				1,604,879
Total assets		$	22,966,319			$	4,070,734			$	2,596,209			$	2,137,075			$	31,770,337
Identifiable Liabilities and Equity
Accounts payable - trade		$	369,840			$	803,124			$	25,215			$	345,924			$	1,544,103
Accrued expenses			–				678,456				–				3,539				681,995
Accrued compensation			3,601,282				–				–				–				3,601,282
Accrued interest			–				–				–				849,913				849,913
Revolver			–				1,105,259				–				–				1,105,259
Senior notes			–				–				304,952				7,116				312,068
Subordinated notes			–				–				–				7,234,559				7,234,559
Obligations under settlement agreement			582,565				–				–				–				582,565
Total current liabilities			4,553,687				2,586,839				330,167				8,441,051				15,911,744
Senior notes			–				–				–				217,451				217,451
Obligations under settlement agreement			2,524,448				–				–				–				2,524,448
Subordinated notes			–				–				–				10,418,569				10,418,569
Total liabilities			7,078,135				2,586,839				330,167				19,077,071				29,072,212
Investment in subsidiaries			7,835,842				7,527,746				2,489,529				(17,853,117	)			–
Series A preferred equity			–				–				–				2,745,000				2,745,000
Common equity			7,053,301				(5,180,443	)			(223,487	)			(1,842,995	)			(193,624	)
Accumulated other comprehensive income			999,041				(863,408	)			–				11,116				146,749
Total members' equity			15,888,184				1,483,895				2,266,042				(16,939,996	)			2,698,125
Total liabilities and equity		$	22,966,319			$	4,070,734			$	2,596,209			$	2,137,075			$	31,770,337

 

 

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

 

		Wholesale Trading				Retail Energy Services				Diversified Investments				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			13,762,348				194,486				–				2,008,229				15,965,063
Professional fees			275,508				225,439				–				1,172,507				1,673,454
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
Marketable 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			79,404				66,251				–				358,643				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		$	10,905,336			$	3,617,812			$	784,169			$	2,254,289			$	17,561,606
Identifiable Liabilities and Equity
Accounts payable - trade		$	353,907			$	415,804			$	–			$	265,933			$	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			9,913,982				2,178,435				784,169				(12,876,586	)			–
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			10,251,990				2,535,049				784,169				(8,822,825	)			4,748,383
Total liabilities and equity		$	10,905,336			$	3,617,812			$	784,169			$	2,254,289			$	17,561,606

  

 

21.

Unaudited & Restated Quarterly Financial Information

 

Presented below is a summary of selected unaudited quarterly financial information for the year ended December 31, 2014, including restated results for the periods ended June 30 and September 3014 as described below.

 

		Quarters Ended
		Mar 31, 2014				Jun 30, 2014				Sep 30, 2014
		As Reported				As Restated				As Restated				Dec 31, 2014
Wholesale trading revenue, net		$	27,021,725			$	4,304,660			$	1,414,252			$	5,871,307
Retail electricity revenue			2,912,526				2,226,834				2,988,460				3,101,656
Total revenues			29,934,251				6,531,494				4,402,712				8,972,963
Operating income (loss)			12,312,038				3,566				(4,638,278	)			(1,237,548	)
Income (loss) before income taxes			11,856,791				(725,513	)			(5,270,693	)			(2,081,401	)
Net income (loss)			11,856,791				(725,513	)			(5,270,693	)			(2,081,401	)
Net income (loss) attributable to common			11,719,523				(862,781	)			(5,407,961	)			(2,218,669	)
Comprehensive income (loss)			11,755,349				(590,223	)			(4,872,127	)			(3,067,455	)

  

Overview and Background

 

After review of the valuation of its open FTR positions in its wholesale trading book during the fourth quarter of 2014, the Company determined that corrections to certain previously reported unaudited interim financial statements were necessary.

 

FTRs are Level 3 derivatives that must be reported on the balance sheet at fair value. However, each entity must develop, validate, and test its own valuation models for these instruments, since, unlike the valuation models for options, for example, there are no generally accepted models for FTRs. The Company completed the model development, testing, and validation process during the fourth quarter of 2014. See also “Note 8 – Fair Value Measurements”.

 

Effects of Restatement

 

Since the Company only began trading FTRs in May 2014, no other reporting periods or financial statements have been affected other than those identified below. The Company has restated its:

·

Consolidated balance sheets as of June 30 and September 30, 2014;

·

Consolidated statements of comprehensive income for the three month periods ended June 30 and September 30, 2014;

·

Consolidated statements of comprehensive income and cash flows for the six months ended June 30, 2014; and

·

Consolidated statements of comprehensive income and cash flows for the nine months ended September 30, 2014.

 

The table below presents the effect of the adjustments related to the restatement of our previously reported financial statements at and for the periods ended June 30, 2014:

 

		As Restated				As Previously Reported				Dollar Change
At June 30, 2014
Consolidated balance sheet
Cash in trading accounts		$	20,001,517			$	17,539,656			$	2,461,861
Total current assets			26,592,504				24,130,643				2,461,861
Total assets			31,149,568				28,687,707				2,461,861
Common equity			9,086,656				6,624,795				2,461,861
Total members' equity			12,565,893				10,104,032				2,461,861
Total liabilities and members' equity			31,149,568				28,687,707				2,461,861
Three Months Ended June 30, 2014
Consolidated statement of comprehensive income
Wholesale trading revenue, net		$	4,304,660			$	1,842,799			$	2,461,861
Total revenues			6,531,494				4,069,633				2,461,861
Operating income (loss)			3,566				(2,458,295	)			2,461,861
Income (loss) before income taxes			(725,513	)			(3,187,374	)			2,461,861
Net income (loss)			(725,513	)			(3,187,374	)			2,461,861
Net income (loss) attributable to common			(862,781	)			(3,324,642	)			2,461,861
Comprehensive income (loss)			(590,223	)			(3,052,084	)			2,461,861
Six Months Ended June 30, 2014
Consolidated statement of comprehensive income
Wholesale trading revenue, net		$	31,326,385			$	28,864,524			$	2,461,861
Total revenues			36,452,933				33,991,072				2,461,861
Operating income			12,315,602				9,853,741				2,461,861
Income before income taxes			11,131,278				8,669,417				2,461,861
Net income			11,131,278				8,669,417				2,461,861
Net income attributable to common			10,856,742				8,394,881				2,461,861
Comprehensive income			11,165,126				8,703,265				2,461,861
Consolidated statement of cash flows
Net income		$	11,131,278			$	8,669,417			$	2,461,861
Increase (decrease) in trading accounts and deposits			(4,644,695	)			(7,106,556	)			2,461,861

 

 

The table below presents the effect of the adjustments related to the restatement of our previously reported financial statements at and for the periods ended September 30, 2014:

 

		As Restated				As Previously Reported				Dollar Change
At September 30, 2014
Consolidated balance sheet
Cash in trading accounts		$	19,838,518			$	16,513,373			$	3,325,145
Total current assets			25,837,344				22,512,199				3,325,145
Total assets			30,713,291				27,388,146				3,325,145
Common equity			3,125,045				(200,100	)			3,325,145
Total members' equity			7,002,848				3,677,703				3,325,145
Total liabilities and members' equity			30,713,291				27,388,146				3,325,145
Three Months Ended September 30, 2014
Consolidated statement of comprehensive income
Wholesale trading revenue, net		$	1,414,252			$	550,968			$	863,284
Total revenues			4,402,712				3,539,428				863,284
Operating income (loss)			(4,638,278	)			(5,501,562	)			863,284
Income (loss) before income taxes			(5,270,693	)			(6,133,977	)			863,284
Net income (loss)			(5,270,693	)			(6,133,977	)			863,284
Net income (loss) attributable to common			(5,407,961	)			(6,271,245	)			863,284
Comprehensive income (loss)			(4,872,127	)			(5,735,411	)			863,284
Nine Months Ended September 30, 2014
Consolidated statement of comprehensive income
Wholesale trading revenue, net		$	32,740,637			$	29,415,492			$	3,325,145
Total revenues			40,855,645				37,530,500				3,325,145
Operating income			7,677,324				4,352,179				3,325,145
Income before income taxes			5,860,585				2,535,440				3,325,145
Net income			5,860,585				2,535,440				3,325,145
Net income attributable to common			5,448,781				2,123,636				3,325,145
Comprehensive income			6,292,999				2,967,854				3,325,145
Consolidated statement of cash flows
Net income		$	5,860,585			$	2,535,440			$	3,325,145
Increase (decrease) in trading accounts and deposits			(2,434,389	)			(5,759,534	)			3,325,145

 

 

22.

Subsequent Events

 

From January 1 to March 25, 2015, the Company sold additional Subordinated Notes totaling $2,391,400 with a weighted average term of 31.4 months and bearing a weighted average interest rate of 13.75%.

 

On January 26, 2015, Cyclone closed on the purchase of a single family home located in New Prague, Minnesota for a price of $198,650, paid in cash. Cyclone intends to spend approximately $60,000 on remodeling the property. When remodeling is complete, the property will be offered for rent, anticipated to be during the spring of 2015.

 

On February 24, 2015, American Land and Cyclone entered into a construction loan agreement for a committed amount of $485,000 secured by a mortgage on Lot 2, Block 1, Territory 1^st Addition, also referred to as “21580 Bitterbush Pass”. The loan is also personally guaranteed by Mr. Krieger. Proceeds will be used to construct a home on the property and draws bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10^th and the note matures on November 24, 2015. The loan may be prepaid in whole or in part at any time without penalty. As of March 25, 2015, the outstanding amount of the loan was $128,247 and the Company was in compliance with all terms and conditions of the agreement.

 

On March 3, 2015 the board approved a resolution authorizing a distribution to members of $4,000,000. The distribution was paid to members on March 18, 2015.

 

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

 

 

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, 2014. 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, 2014.

 

Changes in Internal Control over Financial Reporting

 

After review of the valuation of its open FTR positions in its wholesale trading book during the fourth quarter of 2014, management determined that corrections to certain previously reported unaudited interim financial statements were necessary. FTRs are Level 3 derivatives that must be reported on the balance sheet at fair value. However, each entity must develop, validate, and test its own valuation models for these instruments, since, unlike the Black-Scholes and binomial models for options, for example, there are no generally accepted models for valuing FTRs. In addition, there are no Level 1 or Level 2 pricing inputs that are readily available from third parties or the ISOs to use in determining forward pricing for congestion on the specific positions held by the Company. In management’s judgment, the lack of a fair value model and failure to include FTRs on its open positions checklist and the consequent under-reporting of certain line items on the interim financial statements as of and for the quarterly periods ended June 30 and September 30, 2014 constituted a deficiency in internal control over financial reporting. During the fourth quarter of 2014, the Company completed its FTR valuation model development, testing, and validation process and expanded its closing checklist procedures, and consequently, this deficiency was remediated as of the date of the financial statements. See also “Item 8 - Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements, Note 8 – Fair Value Measurements” and “Item 8 - Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements, Note 21 - Unaudited & Restated Quarterly Financial Information”.

 

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.

 

 

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		49		Chairman of the Board of Governors, Chief Executive Officer, and President
Wiley H. Sharp III (1)		58		Vice President – Finance and Chief Financial Officer
Keith W. Sperbeck		43		Vice President – Operations and Secretary
Stephanie E. Staska (1)		32		Vice President – Risk Management and Chief Risk Officer
David B. Johnson (1, 3)		64		Governor
Mark A. Cohn (2, 3)		58		Governor
William M. Goblirsch (2, 3)		71		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.

 

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 also 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. Effective January 1, 2015, Mr. Cohn entered into an employment agreement with Apollo and consequently is no longer considered an independent governor.

 

William M. Goblirsch was elected a Governor on May 4, 2012. From January 2013 to March 2015, Mr. Goblirsch was employed as Chief Financial Officer and also served as a member of the Board of Governors of Tzfat Spirits of Israel, LLC. 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, Executive Vice President and Chief Financial Officer, and board member of Stockwalk Group Inc. He has also served as Chief Financial Officer 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, Minnesota 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.

 

 

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 presently consists of William Goblirsch. The Company is actively seeking an additional independent governor who will be qualified to be a member of the Audit Committee. 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.

 

 

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 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.

 

 

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, 2014 and 2013:

 

Name and Principal Position		Year		Salary ($)				Bonus ($)				Other Incentive Compensation ($) (1)				All Other Compensation ($) (2)				Total ($)
Timothy S. Krieger		2014			300,000				–				–				14,055				314,055
Chairman of the Board, Chief Executive Officer, and President, PEO		2013			600,000				–				–				17,320				617,320
Wiley H. Sharp III		2014			168,000				100,000				–				9,350				277,350
Vice President - Finance and Chief Financial Officer		2013			173,500				25,000				–				4,790				203,290
Keith W. Sperbeck		2014			180,000				75,000				–				18,887				273,887
Vice President – Operations and Secretary		2013			180,000				–				–				23,554				203,554
Stephanie E. Staska		2014			175,000				35,000				–				22,801				232,801
Vice President – Chief Risk Officer		2013			150,000				45,000				–				22,234				217,234

____________________

(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.

 

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.

 

 

The amount of compensation each governor received in 2014 is shown in the table below:

 

Name and Committee Assignments

Fees Earned or Paid in Cash ($) (1)

Stock Awards ($) (2)

Total ($)

Mark A. Cohn

$

28,000

–

$

28,000

William M. Goblirsch

27,000

–

27,000

Chairman, Audit Committee

Member, Compensation Committee

David B. Johnson

24,500

–

24,500

Chairman, Risk Management Committee

Member, Compensation Committee

____________________

(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 last amended January 21, 2015, effective January 1, 2015 (the “4^th Amendment”). Mr. Krieger is the beneficial owner of 100% of the Company’s outstanding preferred equity interests and 99.5% of its outstanding common equity interests. Pursuant to the amended employment agreement, as of January 1, 2015, Mr. Krieger receives a salary of $50,000 per month from the Company. 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.

 

 

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.

 

On December 19, 2014, the Company and Mr. Sharp amended his employment agreement dated June 16, 2013 (the “Amendment”). The Amendment provides that the Company shall pay Mr. Sharp a salary of $14,000 per month, subject to review and adjustment by the Company on a monthly basis based on both Mr. Sharp’s performance and the performance of the Company. The Amendment provides further that Mr. Sharp is entitled to participate in all benefit plans adopted by the Company, and is entitled to 20 days per year of personal time off. In addition, the Company will pay Mr. Sharp a discretionary bonus of $100,000 for 2014, but will no longer pay Mr. Sharp severance upon his separation from the Company.

 

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 “Item 1 - Business – Wholesale Trading - Market Risk Management” and “Quantitative and Qualitative Disclosures About Market Risk”.

 

 

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.

 

 

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 25, 2015 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			4,960				100.00%
Chairman of the Board, Chief Executive Officer, and President (1)
David B. Johnson			–				0.00%
Governor
William M. Goblirsch			–				0.00%
Governor
Mark A. Cohn			–				0.00%
Governor
Wiley H. Sharp III			–				0.00%
Vice President - Finance and Chief Financial Officer
Keith W. Sperbeck			–				0.00%
Vice President - Operations and Secretary
Stephanie E. Staska			–				0.00%
Vice President – Risk Management and Chief Risk Officer
All governors & executive officers as a group			4,960				100.00%
(7 persons)

____________________

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 2014. 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.

 

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 “Item 8. 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 for its office space in Lakeville, Minnesota. Effective January 1, 2013, the Company entered into a lease with Kenyon for 11,910 square feet at what it believes to be market rates. On September 25, 2014, the lease was amended to reduce the square footage to 10,730. For 2015, under the lease, the Company is required to pay base rent of $11,446, as well as estimated real estate taxes and operating expenses of $8,000 for an approximate total of $19,446 per month.

 

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 2014 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.

 

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 2014 and 2013, the review of the Company’s interim consolidated financial statements for the first, second, and third quarters of 2014 and 2013, and for audit-related, tax, and other services performed in 2014 and 2013.

 

		Years ended December 31,
		2014				2013
Audit fees (1)		$	134,177			$	124,351
Tax fees (2)			35,781				46,190
Other fees (3)			–				5,300
Audit related fees (4)			17,000				–
Total		$	186,958			$	175,841

____________________

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, and consultation on matters related to financial reporting.

 

2 - “Tax fees” include fees billed for professional services rendered for tax returns ($25,400 in 2014 and $38,915 in 2013) and tax advice and planning ($10,381 in 2014 and $7,275 in 2013).

 

3 - “Other fees” includes fees billed for services provided other than the services described above such as miscellaneous research projects and consultations.

 

4 - “Audit related fees” principally include fees billed for professional services rendered in connection with the audit of Cynus Energy Futures, LLC (a wholly owned subsidiary) of the Company.

 

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 2014, the appointment of Baker Tilly Virchow Krause as Independent Registered Public Accountants was approved by the Board.

 

 

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 4.4(i) 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 4.4(ii) to the Registrant’s Form S-1/A filed May 7, 2012)
4.5		Paying Agent Agreement (incorporated by reference to Exhibit 4.5 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)**

 

 

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 10.3 to the Registrant’s Form 8-K filed March 18, 2013)**
10.5		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)
10.6		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)
10.7		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)
10.8		Form of Trader Employment Agreement (incorporated by reference to Exhibit 10.16 to the Registrant’s Form S-1 filed February 10, 2012)
10.9		Market Participant Guarantee Agreement 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)
10.10		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)
10.11		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)**
10.12		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)
10.13		Corporate Guaranty by 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)
10.14		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 Exhibit 10.3 the Registrant’s Form 10-Q filed November 14, 2013)

 

 

Exhibit Number		Description
10.15		Unconditional Corporate Guaranty by Twin Cities Power Holdings, LLC in favor of New York Independent System Operator, Inc. dated November 30, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed December 10, 2013)
10.16		Third Amendment to Employment Agreement dated March 1, 2014 between Twin Cities Power Holdings, LLC and Stephanie Staska (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed March 26, 2014)**
10.17		First Amendment to Employment Agreement dated March 24, 2014 between Twin Cities Power Holdings, LLC and Timothy Krieger (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed March 26, 2014)**
10.18		Amendment to Corporate Guaranty dated August 22, 2013 by Twin Cities Power Holdings, LLC in favor of Midcontinent Independent System Operator, Inc., dated April 14, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed May 9, 2014)
10.19		Guaranty, dated November 5, 2014, by Twin Cities Power Holdings, LLC in favor of Shell Energy North America (US), L.P. for benefit of Discount Energy Group, LLC
10.20		Guaranty, dated November 5, 2014, by Twin Cities Power Holdings, LLC in favor of Shell Energy North America (US), L.P. for benefit of Town Square Energy, LLC
10.21		Guaranty, dated April 25, 2014, by Twin Cities Power Holdings, LLC in favor of Noble Americas Energy Solutions LLC for benefit of Discount Energy Group, LLC
10.22		Guaranty, dated April 16, 2013, by Twin Cities Power Holdings, LLC in favor of PJM Settlement, Inc. for benefit of Twin Cities Power, LLC
10.23		Guaranty, dated April 16, 2013, by Twin Cities Power Holdings, LLC in favor of PJM Settlement, Inc. for benefit of Summit Energy, LLC
10.24		Guaranty, dated April 16, 2013, by Twin Cities Power Holdings, LLC in favor of PJM Settlement, Inc. for benefit of Cygnus Energy Futures, LLC
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)

 

 

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

___________________

*

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.

**

Indicates compensatory plan or agreement

 

 

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 27, 2015		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 27, 2015				Timothy S. Krieger
				Chief Executive Officer, President and Chairman of the Board (principal executive officer)
				/S/ WILEY H. SHARP III
Dated: March 27, 2015				Wiley H. Sharp III
				Vice President – Finance and Chief Financial Officer (principal accounting and financial officer)
				/S/ MARK A. COHN
Dated: March 27, 2015				Mark A. Cohn
				Governor
				/S/ WILLIAM M. GOBLIRSCH
Dated: March 27, 2015				William M. Goblirsch
				Governor
				/S/ DAVID B. JOHNSON
Dated: March 27, 2015				David B. Johnson
				Governor