Item 1 - Business
Definitions
Abbreviation or acronym
Definition
ABN AMRO
ABN AMRO Clearing Chicago, LLC and ABN AMRO Clearing Bank, N.V.
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
BLS
Bureau of Labor Statistics, an agency within the U.S. Department of Labor
Btu; therm; MMBtu
A “Btu” or British thermal unit is a measure of thermal energy or the amount of heat needed to raise the temperature of one pound of water from 39°F to 40°F. A “therm” is one hundred thousand Btu. A “MMBtu” is one million Btu.
C$
Canadian dollars
CAN
Twin Cities Power - Canada, Ltd., a wholly-owned subsidiary of TCE and a second-tier subsidiary of the Company
CCL
Clearwaters Capital, LLC, an affiliate of Schachter
CEF
Cygnus Energy Futures, LLC, a wholly-owned subsidiary of CP and a second-tier subsidiary of the Company
CFTC
Commodity Futures Trading Commission
CLP
Connecticut Light & Power Company, an EDC in Connecticut
CME
CME Group
Company
TCPH and its subsidiaries
CoV
Abbreviates the coefficient of variation, a simple measure of volatility useful for comparing two or more data series; equal to the standard deviation divided by the mean
CP
Cygnus Partners, LLC, a first-tier subsidiary of the Company
CP&U
Community Power & Utility, LLC
CSE
Comparison shopping engine, a web site that compares prices for specific products. While most comparison shopping engines do not offer the products or services themselves, some may earn commissions when users follow the links in the search results and make a purchase from an online vendor
Abbreviation or acronym
Definition
CTG
Chesapeake Trading Group, LLC, a wholly-owned subsidiary of TCP and a second-tier subsidiary of the Company
Degree-days; CDD; HDD
A “degree-day” compares outdoor temperatures to a standard of 65°F. Hot days require energy for cooling and are measured in cooling degree-days or “CDD” while cold days require energy for heating and are measured in heating degree-days or “HDD”. For example, a day with a mean temperature of 80°F would result in 15 CDD and a day with a mean temperature of 40°F would result in 25 HDD.
If heating degree-days are less than the average for an area for a period, the weather was “warmer than normal”; if they were greater, it was “colder than normal”. The converse is true for cooling degree-days - if CDD are less than the average for an area for a period, the weather was “colder than normal”; if they were greater, it was “warmer than normal”.
DOE
U.S. Department of Energy
EDC
Electric distribution company
EIA
Energy Information Administration, an independent agency within DOE
ERCOT
Electric Reliability Council of Texas
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission, an independent regulatory agency within DOE
Form S-1
The Company’s Registration Statement on Form S-1, declared effective by the Securities and Exchange Commission on May 10, 2012, with respect to the Company’s Notes Offering
GAAP
Generally accepted accounting principles in the United States
HTS
HTS Capital, LLC, an affiliate of Schachter
HTS Parties
Schachter, HTS, and CCL collectively
ICE
Intercontinental Exchange®
ISO
Independent System Operator
ISO-NE
ISO New England
kW; kWh
Kilowatt or kilowatt-hour; one thousand watts or watt-hours. Kilowatt-hours are typically used to measure residential energy consumption and retail prices. One kWh is equal to 3,412 Btu, but fuel with a heat content of 7,000 to 11,500 Btu must be consumed to generate and deliver one kWh of electricity.
MISO
Midwest Independent System Operator
MCF
One thousand cubic feet, a common unit of price measure for natural gas. In 2010, one MCF of natural gas had a heat content of 1,025 Btu.
MW; MWh
Megawatt or megawatt-hour; one million watts or watt-hours or one thousand kilowatts or kilowatt-hours. Megawatts are typically used to measure electrical generation capacity and megawatt-hours are the pricing units used in the wholesale electricity market.
NGX
Natural Gas Exchange Inc.
NOAA
National Oceanic and Atmospheric Administration, an agency of the U.S. Department of Commerce
Notes
The Company’s Renewable Unsecured Subordinated Notes issued pursuant to its ongoing Notes Offering
Abbreviation or acronym
Definition
Notes Offering
The direct public offering the Company’s Notes pursuant to a registration statement on Form S-1 declared effective by the SEC on May 10, 2012
NYISO
New York Independent System Operator
OTC
Over-the-counter
PJM
PJM Interconnection
PURPA
Public Utilities Regulatory Policy Act of 1978
RTO
Regional Transmission Organization
Schachter
Robert O. Schachter, an individual
SEC
U.S. Securities and Exchange Commission
SUM
Summit Energy, LLC, a wholly-owned subsidiary of TCP and a second-tier subsidiary of the Company
TCE
Twin Cities Energy, LLC, a first-tier subsidiary of the Company
TCP
Twin Cities Power, LLC, a first-tier subsidiary of the Company
TCPH
Twin Cities Power Holdings, LLC
TSE
Town Square Energy, initially, an accounting division of TCP resulting from the acquisition of the business and assets of CP&U. In March 2013, TSE began the process of reorganizing TSE as a wholly-owned subsidiary of the Company
UI
The United Illuminating Company, an EDC in Connecticut
Watt (W); Watt-hour (Wh)
Although in everyday usage, the terms “energy” and “power” are essentially synonyms, scientists, engineers, and the energy business distinguish between them. Technically, energy is the ability to do work, or move a mass a particular distance by the application of force while power is the rate at which energy is generated or consumed. Energy is measured in joules and power is measured in watts. A watt is equal to one joule per second.
In the case of electricity, power is also equal to voltage or the difference in charge between two points multiplied by amperage or the current or rate of electrical flow. The energy supplied or consumed by a circuit is measured in watt-hours.
For example, when a light bulb with a power rating of 100W is turned on for one hour, the energy used is 100 watt-hours. This same amount of energy would light a 40-watt bulb for 25 hours or a 50-watt bulb for 20 hours.
Multiples and sub-multiples of watts and watt-hours are measured using International Systems of Units (“SI”) conventions as follows:
Company Overview
Through its wholly-owned subsidiaries and divisions, 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, and provides electricity supply services to retail customers in certain states that permit retail choice.
The Company currently has market-based rate authority granted by FERC, is authorized by DOE to export electricity to Canada, is licensed by the state of Connecticut as an electric supplier to retail customers, and has retail electric supplier license applications pending in Massachusetts, New Hampshire, and Rhode Island.
Consequently, the Company has two business segments used to measure its activity - wholesale trading and retail energy services.
Organizational Structure
Our organizational structure is outlined below. Town Square Energy, LLC is not yet active as a wholly-owned subsidiary but is expected to commence operations in 2013.
History
TCPH was formed as a Minnesota limited liability company on December 30, 2009. TCPH now serves as a holding company for TCP, CP, and TCE, each of which previously had common ownership. 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.
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.
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, formerly known as Alberta Power, LLC, was formed on March 27, 2008. Canadian operations were conducted through TCE’s wholly-owned subsidiary, CAN, which was formed on January 29, 2008 as a Canadian unlimited liability corporation. On February 1, 2011, a major restructuring of CAN began. In February 2012, CAN was converted to a regular Alberta corporation and during the third quarter of 2012, after review of the progress of the restructuring, the potential implications of the FERC investigation described in “Legal Proceedings” and the outlook for the subsidiary, management concluded that it was unlikely that CAN would ever be able to provide an adequate return. Consequently, on September 5, 2012, TCE resolved that CAN should cease operations by September 14, 2012. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation, Cessation of Canadian Operations”.
On June 29, 2012, TCP acquired certain assets and the business of CP&U, a retail energy business operating in Connecticut, for $160,000 in cash. 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. In March 2013, the Company began the process of reorganizing TSE as a Delaware limited liability company with the intention of it becoming a wholly-owned subsidiary of TCPH. See “Retail Energy Services”.
The Company is headquartered at 16233 Kenyon Ave, Suite 210, Lakeville, MN 55044, telephone (952) 241-3103. In addition to our headquarters, we operate from five other locations. See “Properties”.
The Electric Power Industry
By virtually any measure, the electric power industry in the U.S. is substantial. According to EIA data, in 2011, the industry generated and sold 3,750 GWh (down 0.1% from 2010) for a little more than $371 billion (up 0.6%) to over 144 million customers (up 0.3%).
U.S. Electric Power Industry Revenue, Unit Sales, Customers, and Average Retail Price 2011 & 2010
Source: U.S. EIA, released October 1, 2012, next release September 2013.
Physically, the nation’s power system includes generation resources, transmission lines, and retail distribution systems. At year-end 2010, the industry’s bulk power system consisted of over 18,000 generating units with net summer capacity of 1,138 GW and almost 173,000 circuit-miles of high-voltage transmission lines. The retail distribution system includes substations, wires, poles, metering, billing, and related support systems. Total assets of the industry are well over $1 trillion.
Today, the industry includes any entity producing, selling, or distributing electricity. Participants include slightly less than 3,100 investor-owned, publicly-owned, cooperative, and federal utilities. Additionally, non-utility power producers include both independent power producers and customer-owned generation facilities. Power marketers and energy service providers do not own any generation but buy and sell in wholesale and retail markets. Finally, participants in wholesale power markets include banks, hedge funds, private equity firms, and trading houses.
Electric power in commercial quantities, unlike other energy commodities such as coal or natural gas, cannot be stored, i.e., the supply must be produced or generated exactly when used or demanded by customers. Further, the laws of physics dictate that power flows within a network along the lines of least resistance, not necessarily where we may want it to go. These facts have obvious implications for electricity market regulations and structures.
The investor-owned portion of the industry has been undergoing a massive restructuring process since the passage of the Public Utilities Regulatory Policy Act of 1978. PURPA stimulated development of renewable energy sources and co-generation facilities and laid the groundwork for deregulation and competition by opening wholesale power markets to non-utility producers of electricity for the first time.
Since PURPA, the nation has moved from a system of vertically integrated, natural monopolies providing retail service at state-determined, cost-based rates to one where the ownership of generation assets is no longer regulated and the majority of the nation’s bulk power systems (generation and transmission) are operated under the supervision of the Federal Energy Regulatory Commission, an independent agency within the U.S. Department of Energy. Today, prices at the wholesale level are determined by market forces, subject to a federal regulatory framework focused on ensuring fair competition and reliability of supply. Furthermore, while some states have restructured their markets such that individual consumers are allowed to choose their electricity supplier, most state public utility commissions continue to regulate their utilities under the traditional cost-based framework.
Wholesale Electricity Markets
After PURPA, the Energy Policy Act of 1992 was the next major legislative step towards full deregulation of wholesale power markets and in 1996, FERC issued Orders 888 and 889, which led to the creation of the network of “OASIS” or Open Access Same-Time Information System nodes, which allowed for energy to be scheduled across multiple power systems.
In December 1999, FERC issued Order 2000 calling for electric utilities to form RTOs or ISOs to operate the nation’s bulk power system with the intended benefits of eliminating discriminatory access to transmission for all generators, improving operating efficiency, and increasing system reliability. ISOs are typically not-for-profit entities using governance models developed by FERC.
FERC’s U.S. Wholesale Electricity Markets
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.
Trading activity in ISO markets is often characterized by the acquisition of electricity at a given location such as a node or hub and its delivery to another. “Virtual” or purely financial transactions settle in cash in an amount equal to the difference between the purchase and sale prices, while physical transactions are settled by the delivery of the electricity itself, but in either case, the ISO serves as the counter-party and central clearinghouse for all trades.
In addition to the markets operated by the ISOs, derivative contracts such as swaps, options, and futures keyed to a wholesale electricity price are traded over-the-counter and on regulated exchanges, including ICE, NGX, and CME. Derivative contracts are available for many terms and pricing points and always settle in cash with profit or loss determined by price movements in the underlying commodity, whether it be electricity or another energy commodity such as natural gas or crude oil.
In the short term, wholesale electricity price levels and changes are driven by supply and demand. Demand is largely affected by the weather and consumer behavior while supply is driven by generation and transmission outages 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.
Retail Electricity Markets
At the state level, in a regulated market, vertically-integrated utilities own all or a major part of the bulk power and distribution infrastructure and are 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 or deregulating 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.
Today, 14 years after Massachusetts and Rhode Island became the first states to effectively implement choice in 1998, 20 jurisdictions have some form of choice:
This un-bundling of consumer electric bills in restructured markets made many aware for the first time exactly what they were paying for. In general, the bills of retail electricity customers include numerous costs and charges that can be classified into three major categories - generation costs, transmission and distribution 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.
·Transmission & Distribution 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.
oTransition charges include costs associated with moving from a regulated market to a restructured one and allow EDCs to recapture stranded costs that would otherwise be unrecoverable after deregulation.
oSocietal benefits charges include the costs of government-mandated programs such as universal service, lifeline service, renewable energy certificates, and energy efficiency programs.
oSales and use taxes include taxes collected by state and local authorities on retail electricity sales.
According to analysis of EIA data, on average between 2007 and 2011, energy costs accounted for about 66% of the average retail electricity price, transmission for 8%, and distribution charges for the rest or 26%. Of course, in a deregulated state, these percentages will fluctuate from year to year, primarily due to wholesale energy market conditions. For example in 2011, when wholesale electricity was relatively cheap, the energy portion decreased to 62%, transmission increased to 9%, and distribution went up to 29%. The following graph, published by the Massachusetts Department of Public Utilities in January 2012, shows the average composition of residential electric bills in the state from 1998 at the start of the restructuring of its electric power industry to 2011 and illustrates this point.
Overall, we believe that choice is proving to be a boon for consumers. According to an analysis of data from the EIA and BLS, between 1997 and 2011, when adjusted for inflation, retail rates for all customer sectors in states with restructured retail markets increased only 1.0% compared with an 8.8% increase in states that rely on monopoly utilities. Furthermore, over this period, inflation-adjusted rates for residential and commercial customers in restructured states have actually decreased by 3.8% and 6.3% respectively, while rates in monopoly states have increased by 4.2% and 2.7%, respectively.
Wholesale Energy Trading
The Company trades financial and physical contracts in wholesale electricity markets managed by ISOs or RTOs (collectively, the “ISOs”) including those managed by MISO, ERCOT, PJM, ISO-NE, and NYISO. 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 and its delivery to another. Financial transactions settle in cash in an amount equal to the difference between the purchase and sale prices, while physical transactions are settled by the delivery of the commodity. ISO-traded financial contracts are also known as virtual trades, are outstanding overnight, and settle the next day. The Company also trades physical electricity between certain markets, buying in one market and selling in another. On ICE, NGX, and CME, from time to time, the Company may trade electricity, natural gas, and oil derivatives and hold an open interest in these contracts overnight or longer.
Business Strategies
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.
Market Risk Management
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: Each trading group, meaning the energy traders within one of our individual operating companies, is 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 trading group must close the entire position immediately, ideally within one trading hour.
Value-at-Risk: Each trading group has a VaR limit. Our daily VaR model is based upon log normal returns calculated from the latest 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 updated to the close of business on the previous day and historical data captured up to and including the previous business day. The histories used are ideally those of the instrument held; however, in the cases where those prices are unavailable, benchmarking is used. The calculation will always use the market value of the position, not its cost. In the case where the liquidity of a position is greater than one day, that is, it will take more than one day to close out the position, 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 five 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.
Competition
Given the nature of the 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 proprietary software system, DataLiveTM, enhances our traders’ success.
Unlike many of our competitors, TCP has market based rate authority under the rules and regulations of FERC. Market based rate authority allows us to trade physical electricity in the United States.
Retail Energy Services
On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC, a retail energy business operating in Connecticut. The business was renamed Town Square Energy (“TSE”) and on July 1, 2012, we began selling electricity to residential and small commercial customers at variable and fixed rates. In general, the Company’s customer arrangements are cancellable by the customer at any time.
Sales and Marketing
Between the acquisition date and year-end, we signed up 4,892 new customers and grew the number of customers taking service from us from less than 150 to 4,258. Our principal marketing strategy has been to offer comparatively low prices to consumers through our website, www.townsquareenergy.com.
Most of our customers come to our site after visiting www.ctenergyinfo.com, a comparison shopping engine offered by the state of Connecticut to its residents. We generally price our contracts such that our offers provide savings compared to the standard offer default rates offered by the incumbent utilities and, consequently, appear in the first two or three listings below their offerings on ctenergyinfo.com.
We have also tested other marketing techniques to a very modest degree and expect to employ other methods such as radio, direct mail, and outbound telemarketing as we expand our operations into other states.
Competition
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 2012, there were about 770 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 have relatively limited margins but a very high quality cash flow and small balance sheets.
Suppliers, also known as retail energy providers or energy service companies, are also licensed by a state to deal with retail customers. They have an up-stream supply arrangement which may include purchasing directly from a pool like PJM or NYISO or bilaterally from large integrated energy companies or independent power producers. In contrast to the 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.
Credit Risk Management
Wholesale Energy Trading
Like other non-rated 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 various ISOs and RTOs and the ICE. We also maintain cash balances in brokerage accounts that facilitate our trading activities. All of these accounts are uninsured. Since we do not trade bilaterally, our only credit exposures are to the ISOs in which we participate and the ICE, NGX, and CME clearing corporations.
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.
Retail Energy Services
We also provide trade credit to retail customers including residential, commercial, and industrial accounts as a result of selling them electricity and this exposes us to certain credit risks which we manage in different ways.
For example, all states with restructured retail markets have implemented laws and regulations with respect to permitted billing, credit, and collections practices. Some require an EDC billing customers in their service territory on our behalf to purchase the receivables generated as a result of energy sales from suppliers operating there, generally at a modest discount to reflect bad debt experience. These states are known as purchase of receivables or “POR” jurisdictions. From the supplier’s point of view, this effectively substitutes the EDC’s credit, which is typically investment grade, for that of our retail customers.
Currently we are only engaged in retail sales in Connecticut, which is a POR state. However, in the near future we also expect to operate in non-POR areas. In non-POR jurisdictions, we intend to manage credit risk based on the type of account and the dollars involved. For example, in the case of residential accounts, the dollars at risk as a result of sales to any one customer are relatively small. Consequently, it is generally not worthwhile to check the credit of each prospect prior to entering into a contract. On the other hand, the dollars involved in serving non-residential customers can be substantial, and we therefore intend to check each such prospect’s credit prior to setting contractual terms, which depending upon the outcome of our credit checks, may include requiring a deposit before accepting the business. Should customers fail to pay, we also intend to pursue appropriate collection measures.
Credit Reviews
Our 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. In addition, we will perform follow-up reviews based on the below schedule. If a guaranty is being utilized to establish credit, the guarantor will be evaluated and credit will be granted based on the financial strength of the guarantor.
Intellectual Property
We have developed a proprietary software system, DataLiveTM, 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. We are in the process of applying for software copyright protection with respect to such system. Currently, we protect DataLiveTM through confidentiality and noncompetition agreements with certain of our employees. We have also developed a proprietary risk management database known as the SQL Database, which delivers price data to our risk managers.
We employ one full time software engineer who develops software tools for our traders. In 2011 and 2012, we spent approximately $207,000 and $165,000, respectively, on research and development of DataLiveTM.
Personnel
As of March 15, 2013, we employed 36 persons, including 20 electricity traders, 2 risk managers, and 14 executives and administrative personnel. We have 33 full-time and 3 part-time employees. We do not employ any unionized labor. We have entered into employment agreements with all of our traders and administrative employees. We also have three independent consultants under contract.
To attract and retain qualified personnel, particularly traders, we employ a competitive compensation system that incorporates dedicated capital and a payout of approximately 35-40% of net revenues. We also have a policy of not requiring traders to relocate. Instead, we have invested in centralized trading platforms and strong risk management disciplines. Consequently, traders can live where they want. Traders are, however, responsible for covering their expenses before sharing in the profits of their trading activities. This strategy also provides them with a sense of being responsible for the success of their own individual trading activities. While we can make no assurances, we believe these policies will help us to retain the successful energy traders who are so vital to our operations and success.
Other employee benefits available through, or paid by, us include medical and dental insurance, a 401(k) plan, employee-managed time off, and holiday pay.
Regulatory Matters
We are required to comply with the rules and regulations of FERC, the U.S. Department of Energy with regard to the export of electricity, the CFTC with respect to energy futures contracts, the Federal Trade Commission, the market rules and tariffs of the ISOs and RTOs of which we are a member, and the laws of the states in which we conduct business. We believe we are fully compliant with all regulations. We conduct annual compliance training in an effort to maintain such compliance.
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.
Item 1A
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 Industry
We are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and results of operations.
We are subject to the jurisdiction of, and required to comply with the rules and regulations FERC, including the Federal Power Act, the U.S. Department of Energy with regard to the export of electricity, the CFTC with respect to energy derivative contracts, the Federal Trade Commission, the market rules and tariffs of the ISOs and RTOs 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 changing governmental policy and regulatory actions, and also the rules, guidelines and protocols of the wholesale 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.
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, RTOs, 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.
Risks Related to Our Businesses
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 result in results of operations, financial condition, and cash flows, lawsuits against us, and regulatory intervention, the impact of which could materially, and adversely, affect 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.
We are largely dependent on our energy traders to generate our revenues.
We are largely dependent on the success of our energy traders to generate our revenues. While we have employment agreements with our traders, we do not have any non-competition agreements in place with these individuals. Accordingly, a trader may leave us at any time. Further, 70% of our revenue in 2011 was generated by our top 5 most successful traders, and in 2012 our top 5 traders generated 60% of our revenue. The loss of any of these traders would have an immediate and potentially material adverse effect on our results of operations and if we are unable to hire replacements with comparable abilities, our results of operations, financial condition, and cash flows would suffer.
If we are unable to successfully compete for the best energy traders, our results of operations may be impaired.
Given the nature of our business, we do not compete with other entities for market share. Instead, we compete with other entities to attract and retain the most qualified energy traders, who are the primary source of our revenue. Our competitors may have greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures, more effective risk management policies and procedures and greater ability than us to withstand losses. Our competitors may also be able to respond more quickly to new laws or regulations or emerging technologies than we can. Our energy traders may leave us at any time to join a competitor or compete directly on their own, which would have an adverse effect on our results of operations and cash flow.
We may not be able to compete successfully against current and future competitors for the most qualified energy traders, and any failure to do so could have a material adverse effect on our business, financial condition, results of operations and cash flow.
We need substantial liquidity to operate our business.
We need substantial liquidity to operate our business. Our access to credit through commercial lenders is limited due to the nature of our business operations and our assets. We have historically funded our operations through borrowings under debt agreements with related and unrelated parties, and internally generated cash flows. Our results of operations, financial condition and cash flows have been and may continue to be adversely affected by the high interest rates we must pay in order to obtain private loans from related and unrelated parties. Beginning in May 2012, we began a direct public offering of our Renewable Unsecured Subordinated Notes and to March 27, 2013, we have raised over $3,153,308. However, we may not be able to obtain sufficient funding for our future operations from such sources to provide us with necessary liquidity.
Our revenues and profitability could be adversely affected if a counter-party defaults in whole or in part on its obligations to us related to our cash deposits in brokerage and collateral accounts.
We maintain cash balances in brokerage accounts that facilitate our trading activities. In addition, we have cash deposits in collateral accounts at various ISOs, RTOs and the ICE. All of these accounts are uninsured. When we place cash deposits in these accounts with a counterparty, we incur credit risk, which is the risk of loss if the counterparty fails to perform according to the terms of our contracts, including safekeeping these funds and releasing the funds to us at an agreed upon time. Our revenues and profitability could be adversely affected if our counterparties were to default in whole or in part on their obligations to us. See “Business -Credit Risk Management”.
TCE is currently subject to an investigation by FERC that could result in liability.
In October 2011, FERC initiated a non-public formal investigation into power scheduling and trading by TCE in MISO. FERC is investigating scheduling and trading for the period from January 1, 2010 through May 31, 2011. In addition to the expense of legal fees, depending on the investigation outcome, we may be liable for potential disgorgement of profits and possible civil penalties. Since this investigation is on-going, we are unable to determine the likelihood of an unfavorable outcome or the amount or range of any potential loss, other than the expenditure of legal fees for defense. However, FERC has the authority to assess fines and penalties of up to $1.0 million per day and, if it is determined that serious offenses have been committed and fines and penalties are imposed, such could have a material adverse effect on us. See “Legal Proceedings”.
We may be unable to run our retail energy services business profitably or recognize expected synergies.
Our entry into the retail energy business will experience all the risks involved in entering into a new line of business, including the risks that we are unable to run the business profitably and that we will not be able to recognize expected synergies. We do not have experience managing a retail electricity business. We will rely heavily, if not entirely, on acquiring existing businesses through which we will enter the market. Such acquisitions may take significant time and effort and distract management from focusing on the Company's current activities.
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.
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 DataLiveä. 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.
Our management has limited experience managing a public company.
Our management team has operated our business as a privately-owned limited liability company. With the exception of our chief financial officer, our management team has no prior experience managing a public company. We continue to develop control systems and procedures adequate to support a public company and this transition could place a significant strain on our management systems, infrastructure, overhead, and other resources.
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
Item 1B - Unresolved Staff Comments
None.
Item 2
Item 2 - Properties
We are headquartered at 16233 Kenyon Ave, Suite 210, Lakeville, MN 55044, telephone (952) 241-3103. In addition to our headquarters, we operate and currently lease office space in four other locations. We do not engage in any production or manufacturing activities, and we do not have any environmental issues related to our energy trading or retail sales operations.
The following table summarizes key terms of the various leases for office space:
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. Beginning March 2013, the Company was obligated to pay $800 per month under a verbal month-to-month lease for office space in in Darien, Connecticut.
The lessor of our headquarters in Lakeville, Minnesota, Kenyon Holdings, LLC (“Kenyon”), is a related party. On January 1, 2013, the Company and Kenyon entered into a new five year lease replacing the old lease and the addenda thereto at what it believes to be market rates. The new lease expires December 31, 2017. See “Certain Relationships and Related Transactions, and Director Independence - Real Estate Lease”.
The lessor of our office space in Tulsa, Oklahoma, the Brandon J. and Heather N. Day Revocable Trust (the “Day Trust”), is a related party. On March 5, 2013, CEF and the Day Trust entered into a three year lease at what the Company believes to be market rates. The lease expires February 28, 2016. See “Certain Relationships and Related Transactions, and Director Independence - Real Estate Lease”.
Item 3
Item 3 - Legal Proceedings
FERC Investigation
On October 12, 2011, FERC initiated a formal non-public investigation into TCE’s power scheduling and trading activity in MISO for the period from January 1, 2010 through May 31, 2011. Depending on the investigation’s outcome, TCE may be liable for potential disgorgement of profits and civil penalties. Since the investigation is still ongoing, the Company is unable to determine the likelihood of an unfavorable outcome or the amount or range of any potential loss, other than the expenditure of legal fees for defense, which are being expensed as incurred. A recent federal court decision held that FERC has no authority to regulate derivatives, which are involved in the FERC investigation. We are unable at this time to determine how this ruling will affect the investigation, if at all.
Former Employee Litigation
On February 1, 2011, the Company commenced a major restructuring of the operations of CAN and all personnel were terminated, although several were subsequently re-hired. During the course of 2011, three former employees commenced legal proceedings and brought separate summary judgment applications seeking damages aggregating C$3,367,000 for wrongful dismissal and payment of performance bonuses. One former employee sought and obtained an injunction to freeze certain bank accounts utilized by CAN containing approximately C$1,814,000. Although the initial injunction was set aside, another former employee obtained an attachment order and the funds remained in trust. The Company filed 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. On April 2, 2012, the Company won its appeal of the attachment order and the funds in trust were released. The total returned was C$1,829,000. All three summary judgment applications were appealed and were heard on July 4, 5, and 6, 2012 by the Alberta Court of Queen’s Bench.
On July 6, 2012, the court dismissed two of the three applications and allowed the third, awarding summary judgment against CAN for a portion of the claim amounting to C$1,376,726. The remainder of the allowed application was ordered to be assessed at a trial. The Company has appealed the allowed application to the Alberta Court of Appeal and the matter is scheduled to be heard June 13, 2013.
As discussed in Note 1. Businesses and Organization, Cessation of Canadian Operations to our financial statements, on September 14, 2012, TCE ceased all operations of CAN. In conjunction therewith, after review of the progress of the restructuring, the potential implications of the FERC investigation described above, and since there were no material assets of CAN available as of either the date of the judgment award or September 14 to satisfy any amount of claim that might be enforceable against CAN, the Company reduced its accrual related to the litigation by C$1,548,570 during the third quarter.
Although it is management’s opinion that the ultimate resolution of the litigation arising as a result of the reorganization of CAN will not have a material effect on its financial position, results of operations, or liquidity, it is possible that this assessment could change by an amount that could be material. Due to the uncertainty surrounding the outcome of the litigation, including that of its counterclaims against the former employees, the Company is presently unable to determine a range of reasonably possible outcomes.
PJM Resettlement
On May 11, 2012, the FERC issued an order denying rehearing motions in regards to PJM resettlement fees confirming its intent to reverse refunds it had granted to a number of market participants in a 2009 order. These refunds were related to transmission line loss refunds issued to the Company by PJM for prior periods. On June 15, 2012 the Company filed a motion for stay pending appeal to FERC; the stay request was denied on July 3, 2012. The Company also filed a stay pending appeal with the U.S. Court of Appeals on June 27, 2012; on July 6, 2012 this request was also denied. Consequently, pursuant to the May 11, 2012 order, the Company was required to return $782,000 to PJM. This amount was paid in full in July 2012.
On July 9, 2012, several parties filed a petition for review of the May 11, 2012 FERC order with the District of Columbia Circuit of the U.S. Court of Appeals. The due date for intervention in this proceeding was August 8, 2012 and certain subsidiaries of TCPH filed motions to intervene in this proceeding as they were not named parties. The case is currently being briefed before the Court of Appeals and final briefs were due by the end of 2012. Oral argument in this appeal is scheduled for April 16, 2013. If FERC’s order is overturned on appeal, some or all of the funds paid to PJM in July 2012 could be returned to the Company. Due to the uncertainty surrounding the outcome of the appeals process, the Company is presently unable to determine a reasonable estimate of the amount, if any, that could be returned.
Item 4
Item 4 - Mine Safety Disclosures
Not applicable.
Part II
Item 5
Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
None.
Item 6
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 Item 7
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 “Item 1A - 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.
Wholesale Energy Trading
Generally, our greatest opportunities for profitable trades occur during periods of market turbulence, when the forecast for supply or demand is more likely to be inaccurate. When demand for energy is relatively stable, price variations tend to be small or non-existent. During periods of market turbulence, prices tend to be volatile, which give our traders the opportunity to take advantage of such volatility. Furthermore, our revenue is limited to some extent by the amount of collateral we have posted with a market operator or exchange as well as the mix between physical and financial contracts. Our primary costs in generating revenue are compensation of our energy traders as well as the interest expense of obtaining the capital necessary to post collateral. The tables below present a breakdown of our trading volume on FERC-regulated markets between physical and financial transactions and detail our open derivative contracts held for trading purposes for and as of the periods and dates indicated:
Open Derivative Contracts Held for Trading
As of December 31, 2012
As of December 31, 2012
Retail Energy Services
We entered the retail energy services business on June 29, 2012 via the CP&U/TSE transaction. Beginning in July 2012, we started selling electricity purchased in the New England wholesale market to both residential and small commercial customers in Connecticut. We primarily use direct marketing strategies to sell our services and our customers may typically cancel their contracts at any time.
In its retail business, the Company is exposed to volatility in the cash cost of the energy acquired for sale to customers. The Company has designated the derivative contracts detailed below as a cash flow hedge for a portion of its expected 2013 cash power purchases for retail.
Open Derivative Contracts Designated as Cash Flow Hedges
As of December 31, 2012
Cessation of Canadian Operations
On February 1, 2011, TCPH commenced a major restructuring of Twin Cities Power - Canada, Ltd., the wholly-owned subsidiary of TCE and a second-tier subsidiary of the Company (“CAN”).
During the third quarter of 2012, after review of the progress of the restructuring, the potential implications of the FERC investigation described in Note 14. Commitments and Contingencies to our financial statements and “Item 3 - Legal Proceedings”, and the outlook for the subsidiary, management concluded that it was unlikely that CAN would ever be able to provide an adequate return. Consequently, on September 5, 2012, TCE resolved that CAN should cease all operations on September 14, 2012.
CAN’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 substantially all accounts, both external and intercompany, were closed except for two bank accounts.
During the years ended December 31, 2012 and 2011, net revenue for CAN was $1,098,000 and $7,734,000, respectively, and operating income was $2,961,891 and $1,734,649, respectively. Operating income in 2012 was positively impacted by the reversal of compensation accruals for former employees totaling $2,361,685 ($779,762 in the second quarter and $1,581,923 in the third quarter). Without such reversals, operating income in 2012 and 2011 would have been $600,206 and $1,734,649, respectively.
Results of Operations
Years Ended December 31, 2012 and 2011
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:
Wholesale trading revenue, net: In our wholesale trading business, we record revenues based upon changes in the fair values of the contracts we trade, net of costs. The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of instruments that remain open at a balance sheet date represent unrealized gains or losses.
On a wholesale level, electricity prices are highly correlated with weather and the price of natural gas, particularly in our key eastern markets, where it is the marginal fuel of choice for most generation. Market conditions during 2012 were characterized by milder than normal weather - with a warmer winter and cooler summer - and cheap and ample natural gas supplies, which suppresses prices. The benchmark price to which much of our wholesale trading is keyed is PJM West Hub and volatility in this index drives many of our revenue opportunities. While our revenues generally track changes in price, other factors come into play as well, such as the size of trades we have in place in terms of megawatt-hours and whether or not we are buying or selling.
The average for the PJM West Peak price during 2012 was $39.85/MWh with a standard deviation of $11.94 resulting in a coefficient of variation of 30%, compared to $51.38/MWh, $20.39, and 40% for 2011. As shown by the table below, both price levels and volatility were generally lower in 2012 as compared to 2011.
According to NOAA data, for 2012, heating degree-days for the U.S. were only 3,789 or 13% below both 2011’s figure of 4,339 and the 30 year normal (1981-2010) of 4,355, making the year one of the warmest on record. Cooling degree-days during 2012 totaled 1,456 compared to a normal of 1,293, making the year about 13% warmer than usual and about 2% warmer than 2011.
EIA data indicates that for 2012, the Henry Hub natural gas spot price averaged $2.75/MCF, 31% below 2011’s $4.00 mark and 46% below the 5 year average price of $5.11. Supplies of gas were ample. Weekly storage levels averaged 3,160 BCF or 18% more in 2012 than in 2011 and were 37% above the 5-year average.
Largely as a result of these factors, for the year ended December 31, 2012, net trading revenue decreased by $24,145,000 or 56.9% to $18,256,000 compared to $42,401,000 for 2011.
Retail electricity sales: Revenue from the retail sale of electricity is recorded in the period in which customers consume the commodity, net of any applicable sales tax. Revenue applicable to electricity consumed by customers but not yet billed under the cycle billing method is estimated and accrued along with the related costs. Changes in estimates are reflected in operations in the period in which they are refined.
Our customer base consists largely of residential consumers with a few small commercial accounts. The following table summarizes our retail results to date. Note that there is a lag between the dates a customer signs up for, or drops, service with us and the date that such transaction takes effect.
Town Square Energy Customer Counts, Load, Usage, Unit Sales, Revenues & Average Price
* Q1 2013 estimated based on operations through Mar 24, 2013.
Costs of retail electricity sold: Our costs of electricity sold includes the cost of purchased power, EDC service fees, renewable energy certificates, bad debt expense, and gains net of losses and commissions on derivative contracts used to hedge power purchase costs. For 2012, the Company purchased all of the electricity sold to retail customers in ISO-NE’s day-ahead and real-time wholesale markets. The Company is required to maintain a cash deposit in a separate account to meet ISO-NE’s financial assurance requirements to purchase energy, ancillary services, and capacity which amount is included in “trading accounts and deposits”.
For the fourth quarter of 2012, we hedged the cost of 5,120 MWh or 54% of the 9,477 MWh of electricity sold to our retail customers in such period. This hedge had the effect of increasing cost of goods sold by $5,683. As of December 31, 2012, we had hedged the cost of 22,160 MWh (approximately 37% of expected 2013 electricity purchases for the customers receiving service from us as of that date) and $82,032, representing the loss on the effective portion of the hedge, was deferred in accumulated other comprehensive income. This amount is expected to be reclassified to cost of energy sold by December 31, 2013.
Salaries, wages, and related expenses: Salaries, wages, and related expenses such as employee benefits and payroll taxes consist primarily of base and incentive compensation paid to our administrative officers, energy traders, and other employees.
For 2012, salaries, wages, and related costs decreased by $12,724,000 or 58.9% to $8,896,000 compared to $21,619,000 for 2011. Our personnel expense is directly related to the revenue we record, since our trader’s compensation is tied to revenue production. In addition to decreased revenue, part of the decrease resulted from a C$2,362,000 adjustment to accrued compensation related to the wind down of CAN.
Professional fees: Professional fees consist of legal expenses, audit fees, tax compliance reporting service fees, and other fees paid for outside consulting services.
For 2012, professional fees increased by $285,000 to $3,183,000 compared to $2,898,000 in 2011. The increase was due in part to $268,000 of fees incurred in 2012 related to our retail energy initiatives. Legal and accounting fees in the 2012 period were also higher in connection with the preparation of our public debt offering and SEC filings. The Company also continues to incur legal fees in connection with the Canadian former employee litigation.
Other general and administrative: Other general and administrative expenses consist of rent, depreciation, travel, outside retail marketing and customer service costs, and all other direct office support expenses.
For 2012, these costs increased by approximately $102,000 to $2,248,000 compared to $2,146,000 for 2011. The increase was primarily related to fees associated with the Margin Line as defined below.
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, 2012, trading tools and subscriptions decreased by $371,000 or 28.2% to $945,000 compared to $1,316,000 for 2011. The restructuring of our Canadian operations beginning in February 2011 was a major contributing factor to this decrease.
Other income (expense): Other expense, net of other income, decreased by $2,003,000 to $1,051,000 for 2012 compared to $3,054,000 for 2011. As the principal component of other expense, interest expense decreased by $1,963,000 to $1,065,000 for the year from $3,028,000 during in 2011. The decrease was attributed primarily to a reduction of $4,008,000 in outstanding debt from $10,288,000 at December 31, 2011 compared to $6,280,000 at December 31, 2012, due principally to the conversion of $2,745,000 of debt to redeemable preferred units and a pay down, net of new issuances, of $3,357,000 during 2012.
Provision for taxes: The tax provision is directly related to foreign income taxes associated with CAN. The decrease in taxes is attributed to a decrease in taxable income for CAN in addition to the write-off of the deferred tax asset associated with the reversal of accrued compensation expense, partially offset by current income tax liabilities.
Preferred distributions: Effective January 31, 2012, TCP sold certain financial rights to 496 of its new issue units to John O. Hanson for a purchase price of $2,745,000, paid by conversion of certain notes payable to him. These preferred units incorporate a cumulative distribution of $45,750 per month, are not convertible, have no corporate governance rights, and are redeemable at any time prior to December 31, 2013 for an amount equal to the purchase price. 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. For the year ended December 31, 2012, preferred distributions totaled $503,000.
Liquidity, Capital Resources, and Cash Flow
We require a significant amount of cash to maintain collateral with the trading markets in which we operate, which in turn allows us to trade in those markets and generate revenues. As such, our capital is largely invested in trading accounts and deposits. Our capital expenditure requirements are nominal, being limited to computer and office equipment, software, and office furniture. Therefore, in any given reporting period, the amount of cash consumed or generated will primarily be due to changes in working capital.
Historically, our capital requirements have been funded by notes payable and operating profits and we are dependent on cash on hand, cash-flow positive operations, and additional financing to service our existing obligations. If we fail to make loan payments when due, certain of our lenders have the option to declare any unpaid principal balances and all accrued interest thereon to be immediately due and payable. Should we incur significant losses from operations within a short period, we would be forced to cover such payments by reducing the balances in our trading accounts. Either of such events would have a detrimental effect on the Company.
We are taxed as a partnership for income tax purposes which means that we do not pay any income taxes. All of our income (or loss) for each year is allocated among holders of our common units who are then personally responsible for the tax liability associated with such income. Our Member Control Agreement provides for distributions of cash to 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 is at the discretion of our Board of Governors and depends on various factors, including our results of operations, financial condition, capital requirements, contractual restrictions, outstanding indebtedness, investment opportunities, and other factors considered by the Board to be relevant. The indenture governing our Notes prohibits us from paying distributions to our members if there is an event of default with respect to the notes or if payment of the distribution would result in an event of default. The indenture also prohibits our Board from declaring or paying any distributions other than tax distributions if, in the reasonable determination of the Governors, the Company would have insufficient cash to meet anticipated redemption or repayment obligations.
We believe we have sufficient cash on hand, coupled with anticipated cash generated from operating activities and the anticipated proceeds from the Notes Offering to meet our cash requirements for at least the next twelve months.
The following table is presented as a measure of our liquidity and capital resources as of the dates indicated:
The table below summarizes our primary sources and uses of cash for the years ended December 31, 2012 and 2011 as derived from the statements of cash flows included in this Form 10-K.
At December 31, 2012, our debt totaled $6,280,000 compared to $10,288,000 as of the prior year end. During 2012, we converted $2,745,000 of debt to redeemable preferred units in a non-cash transaction. We generated $2,889,000 from operating activities and used $289,000 for investments in equipment and furniture and to acquire the business and certain assets of CP&U. We used $2,814,000 for financing activities, including an increase of $394,000 in deferred financing costs, a $1,263,000 net reduction in debt, $1,057,000 in distributions, and a $100,000 payment for redemption of 1,540 of our common units. Of the total distribution amount, $503,000 was paid to the holder of our preferred units and $554,000 was paid to our common unit-holders.
During 2011, we generated $33,420,000 of cash from operations, made $213,000 of capital expenditures, and used $36,098,000 for financing activities. For 2011, cash from operations consisted of reductions in trading account deposits and trade accounts receivable totaling $29,224,000 partially offset by an $8,277,000 decrease in trade accounts payable, due largely to the reduced level of trading activity by our Canadian subsidiary. Our principal use of cash during 2011 was $29,436,000 in payments on debt obligations.
Financing
Effective January 31, 2012, TCP sold certain financial rights, but not governance rights, to 496 new membership units, which we refer to as “preferred units”, to John O. Hanson for a purchase price of $2,745,000, paid by conversion of certain notes payable to him. Effective July 1, 2012, these preferred units were exchanged for preferred units with identical terms issued by TCPH. From the effective date to the redemption date, we shall pay Mr. Hanson or his designee a guaranteed payment or distribution of $45,750 per month. At any time prior to December 31, 2013, we may repurchase the units for $2,745,000. If we do not repurchase the units prior to such date, Mr. Hanson may require Timothy S. Krieger, our Chief Executive Officer, to repurchase them on such date. In addition, should we default on our obligations to Mr. Hanson, payment of all specified amounts has been personally guaranteed by Mr. Krieger.
In February 2012, we executed a $25,000,000 Futures Risk-Based Margin Finance Agreement (the “Margin Line” and the “Margin Agreement”, respectively) with ABN AMRO. The Margin Agreement provides CEF with an uncommitted $25,000,000 revolving line of credit for which it pays a commitment fee of $35,000 per month. Loans under the Margin Agreement are secured by all balances in CEF’s trading accounts with ABN AMRO, are payable on demand, and bear interest at an annual rate equal to 1.00% in excess of the Federal Funds Target Rate, or approximately 1.25%. Under the Margin Agreement, the Company is also subject to certain reporting, affirmative, and negative covenants, including maintenance of minimum account net liquidating equity as defined of $3,000,000, a maximum loan ratio as defined of 12.5:1, and minimum consolidated tangible net worth of 4% of the amount of the Margin Line or $1,000,000. As of December 31, 2012, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants.
On February 20, 2012, the HTS Note was amended to accommodate the Margin Agreement as follows:
•CEF may not draw more than $7,000,000 until the Note is paid in full;
•CEF must maintain not less than $3,000,000 in its ABN AMRO account;
•The Company shall retain as capital all funds drawn under the Margin Agreement until the HTS Note is paid in full;
•The Company shall not distribute to its members, directly or indirectly, any of the proceeds of the Margin Agreement;
•The Company shall maintain a separate accounting with respect to the withdrawal and use of funds; and
•The maturity date of the HTS Note was shortened by one year to October 1, 2013 and, consequently, the Company is required to make a balloon principal payment of $1,943,004 at maturity.
On May 10, 2012, our Form S-1 registration statement relating to our offer and sale of Renewable Unsecured Subordinated Notes (File No. 333-179460) was declared effective by the SEC, and our offering of notes commenced on May 15, 2012. The registration statement on Form S-1 covers up to $50,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes.
For 2012, we incurred $651,000 of offering-related expenses, including marketing and printing expense, additional legal and accounting fees, filing fees, and trustee fees. These costs and expenses are expensed as incurred.
Through March 27, 2013, we have sold a total of $3,153,308 in principal amount of Notes and redeemed $156,000, for a net raise to date of $2,997,308.
Non-GAAP Financial Measures
The Company’s communications may include certain non- GAAP financial measures. A “non-GAAP financial measure” is defined as a numerical measure of a company's financial performance, financial position, or cash flows that excludes, or includes, amounts that are included in, or excluded from, the most directly comparable measure calculated and presented in accordance with GAAP in the company's financial statements.
Non-GAAP financial measures utilized by the Company include presentations of liquidity measures and debt-to-equity ratios. The Company’s management believes that these non-GAAP financial measures provide useful information to investors and enable investors and analysts to more accurately compare the Company's ongoing financial performance over the periods presented.
Critical Accounting Policies and Estimates
Revenue Recognition and Commodity Derivative Instruments
Revenues in our wholesale trading business are derived from trading financial, physical, and derivative energy contracts while those for our retail segment result from electricity sales to end-use consumers.
In our trading activities, contracts with the exchanges on which we trade permit net settlement, including the right to offset cash collateral in the settlement process. Accordingly, we net cash collateral against the derivative position in the accompanying consolidated balance sheets. All realized and unrealized gains and losses on derivative instruments are recorded in revenues.
Revenue from the retail sale of electricity is recorded in the period in which customers consume the commodity, net of any applicable sales tax. In our retail business, we are exposed to volatility in the cost of energy acquired for sale to customers, and as a result, in October 2012, we began using derivatives to hedge or reduce this variability, since changes in the price of certain derivatives are expected to be highly effective at offsetting changes in this cost.
Profits Interest Payments
Two of our second-tier subsidiaries (SUM and CEF) have Class B members. Under the terms of such subsidiaries’ member control agreements, Class B members have no voting rights, are not required to contribute capital, and have no rights to distributions following termination of employment, but are entitled to a defined share of profits while employed. Since Class B members have no corporate governance rights or risk of capital loss (or gain), they do not own non-controlling equity interests and profits interests payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the balance sheet.
For the years ended December 31, 2012 and 2011, we recorded $3,047,294 and $8,402,446, 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, 2012 and 2011 was $777,955 and $412,906, respectively.
Item 7A
Item 7A - Quantitative and Qualitative Disclosures about Market Risk
Not applicable.
Item 8
Item 8 - Financial Statements and Supplementary Data
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, 2012 and 2011, 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, 2012 and 2011, 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 29, 2013
Twin Cities Power Holdings, LLC and Subsidiaries
Consolidated Balance Sheets
As of December 31, 2012 and 2011
See notes to consolidated financial statements.
Twin Cities Power Holdings, LLC and Subsidiaries
Consolidated Statements of Comprehensive Income
For the Years Ended December 31, 2012 and 2011
See notes to consolidated financial statements.
Twin Cities Power Holdings, LLC and Subsidiaries
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2012 and 2011
Twin Cities Power Holdings, LLC and Subsidiaries
Consolidated Statements of Cash Flows (Continued)
For the Years Ended December, 31 2012 and 2011
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, 2012 and 2011
See notes to consolidated financial statements.
Twin Cities Power Holdings, LLC and Subsidiaries
Notes to Consolidated Financial Statements
1. Businesses and 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. The Company, through its subsidiaries, has market-based rate authority granted by the Federal Energy Regulatory Commission, an independent regulatory agency within the U.S. Department of Energy (“FERC” and “DOE”, respectively), is authorized by DOE to export electricity to Canada, is licensed by the state of Connecticut as an electric supplier to retail customers, and has retail electric supplier license applications pending in Massachusetts, New Hampshire, and Rhode Island. Consequently, the Company has two business segments used to measure its activity - wholesale trading and retail energy services.
The Company trades financial and physical contracts in wholesale electricity markets managed by Independent System Operators or Regional Transmission Organizations (collectively, the “ISOs”) including those managed by the Midwest Independent System Operator (“MISO”), the Electric Reliability Council of Texas (“ERCOT”), the PJM Interconnection (“PJM”), ISO New England (“ISO-NE”), and the New York Independent System Operator (“NYISO”). On October 28 and November 27, 2011, the Company withdrew from participation in the wholesale markets operated by the Ontario Independent Electricity System Operator and the California Independent System Operator, respectively. The Company also trades electricity and other energy-related commodities and derivatives on exchanges operated by the Intercontinental Exchange® (“ICE”), the Natural Gas Exchange Inc. (“NGX”), and the CME Group (“CME”). U.S. ISOs are regulated by FERC. The Commodity Futures Trading Commission (“CFTC”) regulates ICE, NGX, and CME.
On June 29, 2012, a subsidiary of the Company, Twin Cities Power, LLC, (“TCP”), acquired certain assets and the business of Community Power & Utility LLC (“CP&U”), a retail energy supplier serving residential and small commercial markets in Connecticut. The business was re-named Town Square Energy (“TSE”), and beginning on July 1, 2012, the Company began selling electricity to retail accounts. Initially, TSE was run as a division of TCP. In March 2013, the Company began the process of reorganizing TSE as a wholly-owned subsidiary of TCPH.
The Company also provided consulting services through its VC affiliate. These services primarily included strategic planning and Sarbanes-Oxley compliance services. VC discontinued offering all consulting services in June 2011.
Organization and Ownership of Holding Company
On November 14, 2011, TCPH entered into an Agreement and Plan of Reorganization with TCP, Cygnus Partners, LLC (“CP”), Twin Cities Energy, LLC (“TCE”), and TCPH’s current members to pursue operating efficiencies not available under the old corporate structure (the “Reorganization”).
Prior to the Reorganization, TCP, CP, and TCE were affiliated through common ownership as follows:
Effective December 31, 2011 following receipt of approval from 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 as follows:
Consequently, after the Reorganization, which made TCPH the sole member of each of TCP, CP, and TCE, the financial statements are presented on a consolidated basis while prior to the Reorganization, the financial statements include the combined financial position, results of operations, and cash flows for what are now TCPH’s first-tier subsidiaries (the “Operating Companies”) as though the exchange of equity interests had occurred as of January 1, 2011. The Reorganization was accounted for as a transaction among entities under common control.
Effective January 31, 2012, TCP sold certain financial rights to 496 of its new issue redeemable preferred membership units (the “preferred units”) to John O. Hanson for a purchase price of $2,745,000, paid by conversion of certain notes payable to him and 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. The preferred units are cumulative and incorporate a defined return (a guaranteed payment or distribution of $45,750 per month), are not convertible, and have no corporate governance rights. At any time prior to December 31, 2013, the preferred units may be repurchased by the Company for the sum of $2,745,000. If TCPH does not repurchase the preferred units prior to such date, Mr. Hanson may require Timothy S. Krieger, the Company’s Chief Executive Officer, to purchase the preferred units on such date. Should the Company default on its obligations to Mr. Hanson, payment of all specified amounts has been personally guaranteed by Mr. Krieger.
On January 1, 2012, the Company redeemed the 1,540 common units held by Michael Tufte for $100,000.
Effective December 31, 2012, Mr. Krieger personally purchased the 525 common units held by DBJ 2001 Holdings, LLC.
The Company’s ownership as of December 31, 2012 is summarized below:
The Operating Companies
TCP is a Minnesota Limited Liability Company formed on January 1, 2007. Prior to January 1, 2010, TCP had two classes of membership interests outstanding, one voting and one non-voting. On January 1, 2010, the non-voting units were redeemed for an immaterial amount. TCP has the following subsidiaries, all of which are Minnesota limited liability companies:
·Vision Consulting, LLC (“VC”) was formed on April 4, 2009 and is 80% owned by TCP. VC has one class of membership units with voting rights. Allocation of income and loss are allocated to the members pro rata based on their membership in the company. The Company has not separately presented the balances attributed to the minority member interest of VC in its financial statements because they are not material. In June 2011, both members of Vision consented to discontinue operations.
·TC Energy Trading, LLC (“TCT”) was formed on May 22, 2009, is 100% owned by TCP, and is currently inactive.
·Chesapeake Trading Group, LLC (“CTG”) was formed on June 16, 2009 and is 100% owned by TCP.
·Summit Energy, LLC, (“SUM”) was formed on December 4, 2009 and has two classes of members - a voting class, Class A, and a non-voting class, Class B. TCP owns 100% of the Class A units, which represent 100% of the equity interest in SUM. The rights of Class B members are limited to specific allocations of income and loss as set forth in the member control agreement and are recorded as profits interests in the year earned. Accordingly, the accompanying balance sheets and statements of comprehensive income do not reflect a non-controlling interest related to Class B members.
CP is a Minnesota Limited Liability Company that was formed by the owners of TCP on March 14, 2008. CP has one class of membership units with voting rights. Allocations of income and losses are made to the members pro rata based on their membership in the Company. CP is consolidated with the following subsidiary:
·Cygnus Energy Futures, LLC (“CEF”) is a Minnesota Limited Liability Company and 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, formerly known as Alberta Power, LLC, is a Minnesota Limited Liability Company which was formed on March 27, 2008. TCE has one class of membership units with voting rights. Allocations of income and losses are made to the members pro rata based on their membership in the Company. TCE is consolidated with the following subsidiary:
·Twin Cities Power - Canada, Ltd. (“CAN”) was formed on January 29, 2008 as a Canadian unlimited liability corporation and converted to a regular Alberta corporation in February 2012. CAN is 100% owned by TCE. CAN was owned by TCP until March 27, 2008 when the members of TCP exchanged their interests in CAN for interests in TCE.
Cessation of Canadian Operations
On February 1, 2011, TCPH commenced a major restructuring of CAN. During the third quarter of 2012, after review of the progress of the restructuring, the potential implications of the FERC investigation (see Note 14. Commitment and Contingencies) and the outlook for the subsidiary, management concluded that it was unlikely that CAN would ever be able to provide an adequate return. Consequently, on September 5, 2012, TCE resolved that CAN should cease all operations on September 14, 2012. CAN’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, both external and intercompany, were closed except for two bank accounts.
During the years ended December 31, 2012 and 2011, net revenue for CAN was $1,098,000 and $7,734,000, respectively, and operating income was $2,961,891 and $1,734,649 respectively. Operating income in 2012 was positively impacted by the reversal of compensation accruals for former employees totaling $2,361,685 ($779,762 in the second quarter and $1,581,923 in the third quarter). Without such reversals, operating income in the years would have been $600,206 and $1,734,649, respectively. See also Note 14. Commitment and Contingencies.
Under the Minnesota Limited Liability Act, members of a Limited Liability Company are generally not responsible for the debts and obligations of the entity. Income, gains, losses, deductions, priority returns, and cash flow are allocated among members based on terms and conditions as outlined in the member control agreement.
2. Summary of Significant Accounting Policies
Consolidation Policy
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.
Cash
The Company deposits its cash in high credit quality financial institutions. The balance, at times, may exceed federally insured limits.
Trading Accounts and Deposits
Cash held in trading accounts may be unavailable at times for immediate withdrawal depending upon trading activity. Cash needed to meet credit requirements and that was available for immediate withdrawal as of December 31, 2012 and 2011 was as follows:
Revenue Recognition
Wholesale Energy Trading
The Company’s wholesale trading activities use derivatives such as swaps, forward sales contracts, futures contracts, and options to generate trading revenues. These contracts are marked to fair value each period in the accompanying consolidated balance sheets and revenues, net of costs, are recorded based on realized and unrealized gains and losses. These transactions are shown as operating activities in the consolidated statements of cash flow.
The Company’s agreements with the ISO’s, ICE, and NGX permit net settlement of contracts, including the right to offset cash collateral in the settlement process. Accordingly, the Company nets cash collateral against the derivative position in the accompanying consolidated balance sheets. All realized and unrealized gains and losses on derivative instruments held for trading purposes are recorded in revenues.
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.
Consulting Revenue
Revenue for consulting services is recognized when the service is performed.
Commodity Derivative Instruments
Objectives for Utilization of Derivative Instruments
In its businesses, the Company is exposed to risk due to changes in commodity prices, interest rates, foreign exchange rates, and credit quality. We manage some of these risks using derivative instruments and account for them in accordance with ASC 815, Derivatives and Hedging (“ASC 815”). ASC 815 requires all derivatives to be recorded on the balance sheet at fair value.
In our wholesale operations, we use derivative contracts for trading purposes, seeking to profit from perceived opportunities driven by expected changes in market prices. In our retail business, the Company is exposed to volatility in the cost of energy acquired for sale to customers, and as a result, 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.
Accounting for Derivative Instruments and Their Impact on Our Financial Statements
In our wholesale energy trading operations, all realized and unrealized gains and losses on derivative instruments are recorded in revenues.
Our retail operations follow the ASC 815 guidance that permits hedge accounting under which the effective portion of gains or losses from the derivative and the hedged item are recognized in earnings in the same period. To qualify for hedge accounting, the hedge relationships must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis.
Hedge effectiveness is the extent to which changes in the fair value of the hedging instrument offset the changes in the cash flows of the hedged item. Conversely, hedge ineffectiveness is the measure of the extent to which the change in fair value of the hedging instrument does not offset those of the hedged item. If a transaction qualifies as a highly effective hedge, ASC 815 permits matching of the timing of gains and losses of the hedged item and the hedging instrument. For a cash flow hedge, the effective portion of any change in the hedging instrument’s fair value is recorded as other comprehensive income until the change in value of the hedged item is recognized in earnings.
For the fourth quarter of 2012, the Company hedged the cost of 5,120 MWh or 54% of the 9,477 MWh of electricity sold to its retail customers in such period. As of December 31, 2012, we had hedged the cost of 22,160 MWh (approximately 37% of expected 2013 electricity purchases for the customers receiving service from us as of that date) and $82,032 of the loss on the effective portion of the hedge was deferred and included in AOCI. This amount is expected to be reclassified to cost of energy sold by December 31, 2013.
The following table lists the fair values of the Company’s derivative assets and liabilities as of December 31, 2012 and 2011:
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:
Accumulated Other Comprehensive Income
The following table provides details with respect to changes in accumulated other comprehensive income (“AOCI”) as presented in our consolidated balance sheets, including those relating to our designated cash flow hedges, for the period from January 1, 2011 to December 31, 2012:
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. Total amortization for the year ended December 31, 2012 was $5,011 and is included in other general and administrative expenses.
Foreign Currency Translation
For foreign subsidiaries whose functional currency is the local foreign currency, balance sheet accounts are translated at exchange rates in effect at the end of the month and income statement accounts are translated at average monthly exchange rates for the period. Foreign currency transactions denominated in a foreign currency result in gains and losses due to the increase or decrease in exchange rates between periods. Translation gains and losses are included as a separate component of equity. Gains and losses from foreign currency transactions are included in other income or expense. Foreign currency transactions resulted in losses of $16,678 and $86,581 for the years ended December 31, 2012 and 2011, respectively.
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.
All receivables are reported at the amount management expects to collect from outstanding balances. Differences between amounts due and expected collections are reported in the results of operations for the period in which those differences are determined. There was no allowance for doubtful accounts as of December 31, 2012 or 2011.
Equipment and Furniture
Equipment and furniture are carried at cost and additions or replacements are capitalized. The cost of equipment disposed of or retired and the related accumulated depreciation are eliminated from the accounts with any gain or loss included in operations. Equipment, computers, and furniture are depreciated using the straight-line method over the estimated useful lives of the assets that range from 3 to 7 years. Leasehold improvements are depreciated using the straight-line method over the shorter of the lease term, or the estimated useful life of the asset. Expenditures for repairs and maintenance are charged to expense as incurred.
Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of
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 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, 2012 and 2011, the Company included $3,047,294 and $8,402,446, respectively, in salaries, wages, and related taxes, representing the allocation of profits interests to Class B members.
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.
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 7. Intangible Assets.
Income Taxes
Except for CAN, the Company’s subsidiaries are not taxable entities for federal income tax purposes. As such, the Company does not directly pay federal income tax. Taxable income or loss, which may vary substantially from the net income or net loss reported in our consolidated statements of comprehensive income, is includable in the federal income tax returns for each member. The holder of the Company’s preferred units is taxed based on distributions received, while holders of common units are taxed on their proportionate share of the Company’s taxable income. Therefore, no provision or liability for federal or state income taxes has been made for those entities.
CAN files tax returns with the Canada Revenue Agency and the Tax and Revenue Administration of Alberta.
In accounting for uncertainty in income taxes, we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. The Company recognizes interest and penalties on any unrecognized tax benefits as a component of income tax expense. Based on evaluation of the Company’s tax positions, management believes all positions taken would be upheld under an examination.
The Company’s federal and state tax returns are potentially open to examinations for the years 2008 through 2012 and its Canadian tax returns are potentially open to examination for the years 2009 through 2012.
On November 12, 2012, a letter from the Minnesota Department of Revenue was received notifying the Company that TCP’s 2009, 2010, and 2011 returns are under review by the Department.
New Accounting Pronouncements
In January 2010, the Company adopted FASB ASU No. 2010-06, Fair Value Measurement and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (“ASU 2010-06”). This standard required new disclosures on the amount and reason for transfers in and out of Level 1 and Level 2 fair value measurements. The standard also required new disclosures of activities, including purchases, sales, issuances, and settlements within the Level 3 fair value measurements and clarified existing disclosure requirements on levels of disaggregation and disclosures about inputs and valuation techniques. The standard was effective for the Company on January 1, 2011 and its adoption did not have a material impact on the Company’s financial statements.
In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 amends ASC 820, Fair Value Measurements (“ASC 820”), and changes certain fair value measurement principles, clarifies the application of existing fair value measurement, and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 was effective for the Company’s fiscal year beginning January 1, 2012 and its adoption did not have a material effect on the Company’s financial statements.
In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either a continuous statement or two separate but consecutive statements. ASU 2011-05 was effective for the Company’s fiscal year beginning January 1, 2012. The Company’s adoption of ASU 2011-05 did not have a material impact on its financial position or results of operations.
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires an entity to disclose information about offsetting and related arrangements on its financial position and includes the effect or potential effect of rights of offset associated with an entity’s recognized assets and liabilities. Furthermore, it requires improved information about financial instruments and derivative instruments that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The amendment is effective for annual reporting periods beginning on or after January 1, 2013 and retrospective disclosure is required for all comparative periods presented. No early adoption is permitted. The Company believes that the adoption of ASU 2011-11 will not have any impact on the Company's consolidated results of operation and financial condition but may require certain additional disclosures.
In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) - Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income which requires detailed disclosures of the amounts reclassified out of accumulated other comprehensive income. These disclosure requirements do not change how net income or comprehensive income is presented in the consolidated financial statements and are effective for annual reporting periods beginning on or after December 15, 2012 and interim periods within those annual reporting periods. The Company does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.
Reclassifications
Certain amounts reported in prior periods have been reclassified to conform to the current period’s presentation. There was no effect on members’ equity or net income as previously reported.
3. Segment Information
The Company has two business segments used to measure its business activity - wholesale trading and retail energy services:
·Wholesale trading activities earn revenue from trading financial and physical electricity in wholesale markets regulated by FERC. The Company also trades energy-related derivative contracts on exchanges regulated by the CFTC.
·Beginning on July 1, 2012, the Company began selling electricity to residential and small commercial customers in Connecticut.
These segments are managed separately because they operate under different regulatory structures and are dependent upon different revenue models. The performance of each is evaluated based on the operating income or loss generated. For the year ended December 31, 2012, there were no internal transactions between reportable segments. Information on segments for the year ended December 31, 2012 is as follows:
* Wholesale Energy Trading revenue is net of costs.
4. Financial Instruments
The Company holds various financial instruments. The nature of these instruments and the Company’s operations expose the Company to foreign currency risk, fair value risk, and credit risk.
A portion of the Company’s assets and liabilities are denominated in Canadian dollars (“C$”) and are subject to fluctuations in exchange rates. The Company does not have any exposure to any highly inflationary foreign currencies.
The fair values of the Company’s cash, accounts receivable, and accounts payable were considered to approximate their carrying values at December 31, 2012 and 2011 due to the immediate and short-term nature of the accounts. The fair value of related party notes payable may be different from their carrying values. No assessment of the fair value of these obligations has been completed and there is no readily available market price. However, management believes that the carrying values are a reasonable approximation of fair value at December 31, 2012 and 2011.
Management believes the carrying values of the Company’s notes payable, renewable unsecured subordinated notes, and redeemable preferred units reasonably approximate their fair value at December 31, 2012 and 2011 due to the relatively new age of these particular instruments.
5. Concentrations of Credit Risk
Financial instruments that subject the Company to concentrations of credit risk consist principally of trading accounts and deposits and accounts receivable. The Company has a risk policy that includes value-at-risk calculations, position limits, stop loss limits, stress testing, system controls, position monitoring, liquidity guidelines, and compliance training.
At any given time there may be a concentration of receivables balances with one or more of the exchanges upon which 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.
As of December 31, 2012, there were two accounts with receivable balances greater than 10% that together aggregated 95% of total consolidated accounts receivable. As of December 31, 2011, there were three individual accounts with receivable balances greater than 10% that aggregated 100% of total consolidated accounts receivable. The Company believes that any risk associated with these concentrations would be minimal, if any.
6. Fair Value Measurements
The Fair Value Measurement Topic of FASB’s ASC establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three levels of the fair market hierarchy are as follows:
·Level 1 inputs are quoted prices in active markets for identical assets or liabilities.
·Level 2 inputs are inputs other than quoted prices in active markets that are observable for the asset or liability, either directly or indirectly.
·Level 3 inputs are unobservable inputs for which little or no market data exists.
Determination of fair value for electricity derivative contracts is complex and relies on judgments concerning future prices, volatility, and liquidity, among other factors. All of the derivatives traded by the Company are traded on exchanges with quoted market prices for identical instruments. There have been no changes in the methodologies used since December 31, 2011.
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the valuation methods are considered appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
The following table presents the amounts of assets measured at fair value on a recurring basis as of:
7. Intangible Assets
On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC (“CP&U”), a retail energy supplier serving residential and small commercial markets in Connecticut, for $160,000. The business has been re-named “Town Square Energy” and is run as an accounting division of TCP. 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.
Total amortization for the year ended December 31, 2012 was $34,674 and is included in other general and administrative expenses.
8. Equipment and Furniture
Equipment and furniture consisted of the following at December 31:
Depreciation expense including leasehold amortization expense was $210,989 and $174,873 for the years ended December 31, 2012 and 2011, respectively.
9. Debt
Notes payable by the Company are summarized as follows:
Notes payable by maturity are summarized as follows:
The Margin Agreement
In February 2012, the Company executed a Futures Risk-Based Margin Finance Agreement (“Margin Agreement”) with ABN AMRO. The Margin Agreement provides CEF with an uncommitted $25,000,000 revolving line of credit on which it pays a commitment fee of $35,000 per month. Any loans outstanding are payable on demand and bear interest at an annual rate equal to 1.00% in excess of the Federal Funds Target Rate, or approximately 1.25%. The Margin Line is secured by all balances in CEF’s trading accounts with ABN AMRO. Under the Margin Agreement, the Company is also subject to certain reporting, affirmative, and negative covenants, including certain financial tests.
As of December 31, 2012, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants. See Borrowings from HTS for certain restrictions on the Margin Agreement not imposed by ABN AMRO, but in connection with an amendment to the HTS Note.
Borrowings from HTS
Between 2006 and 2010, TCP borrowed a total of $30,800,000 from the HTS Parties. HTS was a member of the Company and a related party until March 23, 2011 when its membership interests were re-purchased by the Company.
In May 2010, the HTS Parties called the loans, the outstanding balance of which was $28,550,000 as of December 31, 2010. On March 11, 2011 the parties reached a Settlement Agreement that defined terms of repayment, as well as provided for a binding arbitration procedure to resolve other outstanding disputes. By July 1, 2011, the Company had repaid the entire principal balance outstanding, paid accrued interest of $1,640,958, and reduced the HTS Parties capital account balance by a payment of $1,000,000. Following resolution of the dispute between the HTS Parties and the Company, all amounts owed to the HTS Parties as of September 30, 2011, including the HTS Parties’ remaining capital account balance, unpaid interest, and legal fees were converted into a new $5,829,017 note dated October 1, 2011 (the “HTS Note”).
The HTS Note contains certain affirmative and negative covenants including delivery of quarterly and annual financial statements and annual tax returns, maintenance of business, and restrictions on additional indebtedness, as well as specifying certain events of default. The HTS Note is jointly and severally guaranteed as to payment of up to $3,711,486 by Timothy Krieger and Michael Tufte. Initially, the HTS Note was payable in twelve equal quarterly installments of principal of $485,751 plus interest at 15% per annum until maturity on October 1, 2014. However, on February 20, 2012, the HTS Note was amended to accommodate the Margin Agreement as follows:
·CEF may not draw more than $7,000,000 until the Note is paid in full;
·CEF must maintain not less than $3,000,000 in its ABN AMRO account;
·The Company shall retain as capital all funds drawn under the Margin Agreement until the HTS Note is paid in full;
·The Company shall not distribute to its members, directly or indirectly, any of the proceeds of the Margin Agreement;
·The Company shall maintain a separate accounting with respect to the withdrawal and use of funds; and
·The maturity date of the HTS Note was shortened by one year to October 1, 2013, and consequently, on such date, the Company shall make its regular principal payment of $485,751 plus a balloon principal payment of $1,943,004 for a total of $2,428,759.
As of December 31, 2012 and 2011, the Company was in compliance with all covenants with respect to the HTS Note.
Related Party Indebtedness
On September 1, 2006, April 1, 2008, and April 8, 2011, TCP and its predecessor entered into certain borrowing arrangements with John O. Hanson, all accruing interest at an annual rate of 20%. As of December 31, 2012, 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. See Note 13. Ownership. As a result of these transactions, as of December 31, 2012, the Company owed Mr. Hanson $200,000.
As of December 31, 2012 and 2011, the Company was in compliance with all covenants with respect to its obligations to Mr. Hanson.
On May 21, 2012, TCP and Patrick C. Sunseri entered into a First Amendment to the Loan Agreement, Secured Promissory Note, and Security Agreement dated July 16, 2009 (the “Sunseri Loan”). The Amendment changes the annual interest rate to the lower of 15% or the highest rate permitted by law, provides for the repayment of the Loan’s principal and interest over a twelve month period beginning May 1, 2012, adds TCPH as a corporate guarantor with respect to TCP’s obligations to Mr. Sunseri, and adds certain financial covenants and events of default.
At December 31, 2012 and 2011, the Company was not in compliance with all of the covenants on the Sunseri Loan and they were not enforced by the lender. Moreover, none of the technical defaults were waived as the Company did not seek waiver.
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.
As of December 31, 2012, the Company had $2,013,138 of its Subordinated Notes outstanding as follows:
Interest on the Subordinated Notes is paid monthly, quarterly, semi-annually, annually, or at maturity at the sole discretion of each investor and the Company made interest payments during the year ended December 31, 2012 of $16,587. Total accrued interest on the Subordinated Notes at December 31, 2012 was $50,553.
10. Income Taxes
Income tax expense represents the sum of current and deferred taxes. Current taxes payable are based on taxable profits for the year using tax rates that have been enacted or substantively enacted by the balance sheet date.
Components of income tax expense applicable to continuing operations for foreign taxes are as follows:
The difference between the statutory federal income tax rate and the Company’s effective income tax rate is summarized as follows:
The Company’s deferred tax asset in the amount of $526,486 as of December 31, 2011 related solely to accrued compensation associated with Canadian operations. In 2012, the deferred tax asset was reversed due to the reversal of certain accrued compensation. See Note 1. Cessation of Canadian Operations.
11. Leases
The Company leases office space and equipment. The following table summarizes key terms of the various leases for office space.
* See Note 13. Related Party Transactions and Note 15. Subsequent Events.
**See Note 15. Subsequent Events.
In November 2011, the Company became obligated to pay $400 per month under a verbal month-to-month lease in Wellesley, Massachusetts. In addition, the Company has entered into several leases for office equipment that expire between 2013 and 2015.
Total lease expense for office space and equipment was $496,816 and $482,689 for the years ended December 31, 2012 and 2011, respectively.
Future minimum lease payments under the Company’s lease agreements are as follows:
12. 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.
13. Related Party Transactions
During 2010 and 2011, the Company loaned funds to two members. The promissory notes provided for interest at 6% per annum, payable annually. The total advance to each member was $120,000 as of December 31, 2010 and the Company forgave these promissory notes in December 2011.
The following table summarizes notes payable to related parties at December 31:
Interest expense associated with related party notes was $252,942 and $1,556,175 for the years ended December 31, 2012 and 2011, respectively.
On June 23, 2011, the building in which the Company leases its Lakeville, Minnesota office space was sold to Kenyon Holdings, LLC (“Kenyon”), a company owned by Timothy S. Krieger, the Company’s Chief Executive Officer and controlling member and Keith W. Sperbeck, its Vice President of Operations. The existing lease with the Company was assumed from the previous owner by Kenyon, pursuant to which the Company is required to pay base rent, real estate taxes, and operating expenses.
On November 21, 2011, the Company amended the lease, increasing the amount of rented space from 6,378 to 8,333 square feet, increasing the monthly rent from $7,972 to $10,416, and extending the lease term by two years and three months.
During 2012 and 2011, $207,109 and $102,016 was paid to Kenyon for rent, real estate taxes, and operating expenses.
14. Commitments and Contingencies
FERC Investigation
On October 12, 2011, FERC initiated a formal non-public investigation into TCE’s power scheduling and trading activity in MISO for the period from January 1, 2010 through May 31, 2011. Depending on the investigation’s outcome, TCE may be liable for potential disgorgement of profits and civil penalties. Since the investigation is still ongoing, the Company is unable to determine the likelihood of an unfavorable outcome or the amount or range of any potential loss, other than the expenditure of legal fees for defense, which are being expensed as incurred.
Former Employee Litigation
On February 1, 2011, the Company commenced a major restructuring of the operations of CAN and all personnel were terminated, although several were subsequently re-hired. During the course of 2011, three former employees commenced legal proceedings and brought separate summary judgment applications seeking damages aggregating C$3,367,000 for wrongful dismissal and payment of performance bonuses. One former employee sought and obtained an injunction to freeze certain bank accounts utilized by CAN containing approximately C$1,814,000. Although the initial injunction was set aside, another former employee obtained an attachment order and the funds remained in trust. The Company filed 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. On April 2, 2012, the Company won its appeal of the attachment order and the funds in trust were released. The total returned was C$1,829,000. All three summary judgment applications were appealed and were heard on July 4, 5, and 6, 2012 by the Alberta Court of Queen’s Bench.
On July 6, 2012, the court dismissed two of the three applications and allowed the third, awarding summary judgment against CAN for a portion of the claim amounting to C$1,376,726. The remainder of the allowed application was ordered to be assessed at a trial. The Company has appealed the allowed application to the Alberta Court of Appeal and the matter is scheduled to be heard June 13, 2013.
As discussed in Note 1. Businesses and Organization - Cessation of Canadian Operations to our financial statements, on September 14, 2012, TCE ceased all operations of CAN. In conjunction therewith, and after review of the progress of the restructuring, the potential implications of the FERC investigation described above, and since there were no material assets of CAN available as of either the date of the judgment award or September 14 to satisfy any amount of claim that might be enforceable against CAN, the Company reduced its accrual related to the litigation by C$1,548,570 during the third quarter.
Although it is management’s opinion that the ultimate resolution of the litigation arising as a result of the reorganization of CAN will not have a material effect on its financial position, results of operations, or liquidity, it is possible that this assessment could change by an amount that could be material. Due to the uncertainty surrounding the outcome of the litigation, including that of its counterclaims against the former employees, the Company is presently unable to determine a range of reasonably possible outcomes.
PJM Resettlement
On May 11, 2012, the FERC issued an order denying rehearing motions in regards to PJM resettlement fees confirming its intent to reverse refunds it had granted to a number of market participants in a 2009 order. These refunds were related to transmission line loss refunds issued to the Company by PJM for prior periods. On June 15, 2012 the Company filed a motion for stay pending appeal to FERC; the stay request was denied on July 3, 2012. The Company also filed a stay pending appeal with the U.S. Court of Appeals on June 27, 2012; on July 6, 2012 this request was also denied. Consequently, pursuant to the May 11, 2012 order, the Company was required to return $782,000 to PJM. This amount was paid in full in July 2012.
On July 9, 2012, several parties filed a petition for review of the May 11, 2012 FERC order with the District of Columbia Circuit of the U.S. Court of Appeals. The due date for intervention in this proceeding was August 8, 2012 and certain subsidiaries of TCPH filed motions to intervene in this proceeding as they were not named parties. The case is currently being briefed before the Court of Appeals and final briefs were due by the end of 2012. Oral argument in this appeal is scheduled for April 16, 2013. If FERC’s order is overturned on appeal, some or all of the funds paid to PJM in July 2012 could be returned to the Company. Due to the uncertainty surrounding the outcome of the appeals process, the Company is presently unable to determine a reasonable estimate of the amount, if any, that could be returned.
Guarantees
TCPH has provided guarantees of $2,800,000 for future obligations of TCP, SUM, and CEF with respect to their participation in MISO and PJM and also guarantees $5,000,000 of future obligations of TCE with respect to its participation in ERCOT. The Company has also guaranteed payment of TCP’s obligations with respect to the Sunseri loan.
15. Subsequent Events
From January 1 to March 27, 2013, the Company sold additional Subordinated Notes totaling $1,059,170 with a weighted average term of 30.9 months and bearing a weighted average interest rate of 13.76%.
On January 1, 2013, the Company and Kenyon entered into a new five year lease replacing the old lease and the addenda thereto at what it believes to be market rates. The new lease expires December 31, 2017 and is for 11,910 square feet at a monthly rent of $12,264.
Effective January 1, 2013, the Company entered in a Non-Competition Agreement with David B. Johnson, a current governor and former member of the Company, pursuant to which the Company is obligated to pay Mr. Johnson $500,000 in twenty-four equal monthly installments of $20,833 each.
Effective January 18, 2013, TCPH terminated the guarantee agreement of $5,000,000 with ERCOT.
Beginning March 2013, the Company was obligated to pay $800 per month under a verbal month-to-month lease for office space in in Darien, Connecticut.
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 and a related party to the Company.
The Company has evaluated subsequent events occurring through the date that the financial statements were issued.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A
Item 9A - Controls and Procedures
The Company maintains a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2012, the Company’s disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting
During the year ended December 31, 2012, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting, except that we completed execution of our remediation plan to address a material weakness surrounding the close and financial reporting process.
In completing their audit of the Company's 2010 and 2009 combined financial statements, our auditors identified a material weakness in the Company's internal control over financial reporting which resulted in material audit adjustments that were not detected or prevented in a timely manner. The cause of the material weakness was determined to be a lack of personnel with sufficient knowledge to properly apply generally accepted accounting principles to certain transactions, including the disclosure of derivative financial instruments and recording of accrued distributions and compensation to the Company's members.
Beginning in 2010 and continuing into 2011, the Company made investments to strengthen its accounting and financial reporting function including engaging the assistance of an outside consultant with public company financial reporting experience to assist with the oversight and leadership of the Company's external financial reporting function as well as hiring an additional certified public accountant. However, the staff had limited experience in demonstrating the ability to consistently prepare timely and accurate annual and interim financial statements that conformed to the financial accounting and reporting requirements of the SEC. In March 2011, the Company terminated and shortly thereafter replaced its chief financial officer.
In March 2012, the chief financial officer was again replaced. The new chief financial officer has substantial experience as an investment banker and as a senior corporate financial officer for both privately held and publicly reporting companies in a variety of industries beginning in 1979, knowledge and experience that the Company had not had before.
The Company now believes that its finance and accounting functions are adequately staffed by four qualified and knowledgeable professionals. Controls have been put in place for the proper review and approval of all financial transactions and the periodic closing and reporting processes, including the preparation of accurate and timely financial statements free of material misstatements and in conformance with the requirements of the SEC. There have been no material adjustments proposed by the Company’s independent auditors since the 2010 audit and over the last year, the finance and accounting staff have successfully met all SEC filing deadlines for financial statements. Consequently, the Company feels that the material weakness has been resolved.
This annual report does not include a report of management’s assessment regarding internal control over financial reporting due to a transition period established by rules of the SEC for newly public companies.
Item 9B
Item 9B - Other Information
None.
Part III
Item 10
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 a board of governors. Our governors hold office until the election and qualification of their successors. Officers, also referred to as managers under our Member Control Agreement, are elected by the board of governors and serve at the direction of the board of governors. Our governors generally serve the same role as directors do for corporations.
The following table lists our executive officers and governors:
Timothy S. Krieger has served as the Chairman of the Board, Chief Executive Officer and President of TCPH since December 21, 2011, and prior to that served as the only officer and governor of TCPH since it was formed in December 2009. Mr. Krieger also serves as the CEO/President and a governor for all of our direct and indirect subsidiaries. Mr. Krieger has served in such capacities at TCP and CF since the inception of each, in 2006 and 2008, respectively. 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 business, including serving as the Chief Executive Officer of TCPH and our subsidiaries, TCP and CP, since they were formed.
Wiley H. Sharp III was appointed Vice President of Finance and Chief Financial Officer of TCPH 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 TCPH 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 2nd 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 from November 2006 to August 2008. 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 as a governor as of January 4, 2013. Mr. Cohn is currently the Chairman and Chief Executive Officer of Third Season, LLC, a company founded as an incubator of micro-consumer marketing companies, a position he has held since founding the company in 2003. During 2010, he was also the Managing Director and Chief Executive Officer of Dorado Ocean Resources Limited, a deep ocean mining company. From 2003 to 2009, he served as Chief Executive Officer of Second Act, an e-commerce company focused on the resale of consumer electronics. Mr. Cohn served as Chairman, President and Chief Executive Officer of Intelefilm Corporation from October 2001 to August 2002. From its inception in 1986 until February 2001, Mr. Cohn was founder and Chief Executive Officer of Damark International, Inc., a consumer catalog company. During that time, Damark grew to become one of the nation’s largest consumer marketing companies with revenues of $600 million. At its peak, Damark had a market capitalization of over $500 million and employed 2,000 people in three states. Mr. Cohn currently serves as a member of the Board of Directors of Christopher and Banks Corporation, a specialty retailer of women’s clothing (NYSE-CBK) with over 650 stores in the US. In 2012, the National Association of Corporate Directors named him a Governance Fellow. Over the past 25 years, Mr. Cohn has served as CEO or a board member for many private and public for profit, and non-profit, companies or organizations in industries including retailing, distribution, internet, broadcasting, health care, natural resources, manufacturing, and motorsports. Over that time he has gained experience in, among other areas, marketing and finance which provides him a valuable perspective on many of the issues the Company faces and positions him well to serve as a member of our board and its compensation and audit committees.
William M. Goblirsch was elected as a governor as of May 4, 2012. Mr. Goblirsch is a certified public accountant (inactive license) who started his career forty years ago with Arthur Andersen. For the past five years he has been utilizing his financial experience as an independent consultant. He has served as a CFO for several companies including an investment banking firm; a blender, packager and distributor of oil products and lubricants; a cellular air time reseller; and a shopping mall franchisor of dental centers. Mr. Goblirsch has been, at various times, financial consultant to the creditors’ committee, EVP-CFO, and board member of Stockwalk Group Inc. As of January 1, 2013, Mr. Goblirsch is employed as Chief Financial Officer of Tzfat Spirits of Israel, LLC and serves as a member on their Board of Governors. 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 on the board of governors of TCPH 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 headquartered in St. Louis, MO, 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, headquartered in Minneapolis, MN, of which Mr. Johnson was a founder, and lastly served as Chief Executive Officer. Mr. Johnson graduated from Augsburg College in Minneapolis, MN in 1973 with a BS in business. The principal qualifications that led to Mr. Johnson’s selection as a governor include his experience with growth companies and companies that undergo initial public offerings.
Board Composition, Election of Governors, and Committees
Our board of governors 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 of governors 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 of governors.
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 of Governors and the Audit Committee informed of all risk management activities.
The RMC also has the following responsibilities:
·Guide management in risk policy development and adopt, subject to Board approval, the risk policies, restrictions, and limitations of the Company and its traders;
·Guide development in risk appetite, limits setting, and exception protocols;
·Develop and gain consensus of risk management policy, strategy, appetite, and roll-out plans;
·Develop and guide in the implementation of risk management and measurement approaches;
·Approve resource requirements;
·Evaluate risk responsiveness of the organization’s risk events;
·Communicate risk management progress and successes to the Board;
·Monitor and fine-tune risk management processes as required;
·Identify data and information system requirements to support risk management function;
·Contemporaneously communicate to the Board any risk profile changes;
·Monitor corporate compliance with risk limits and policies and report to Board on compliance; and
·Identify gaps in existing policies, systems, and procedures.
Audit Committee
Our audit committee consists of William Goblirsch, who serves as chair, and Mark Cohn, both of whom are independent. The audit committee assists our board of governors 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.
Our 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 services to be provided to us and all non-audit services, other than de minimus non-audit services, to be provided to us by our independent registered public accounting firm must be approved in advance by our audit committee.
Compensation Committee
Our compensation committee consists of Mark Cohn, who serves as chair, David Johnson, and William Goblirsch, and assists our board of governors in the discharge of its responsibilities relating to the compensation of our executive officers.
Our compensation committee’s responsibilities include:
·Reviewing and approving, or making recommendation to the board of governors with respect to, our chief executive officer’s compensation;
·Evaluating the performance of our executive officers and reviewing and approving, or making recommendations to the board of governors with respect to, the compensation of our executive officers;
·Overseeing and administering, and making recommendations to the board of governors with respect to any cash and equity incentive plans that the board may adopt; and
·Reviewing and making recommendations to the board of governors with respect to governor compensation.
Item 11
Item 11 - Executive Compensation
Twin Cities Power Holdings, LLC was formed in December 2009 and became the holding company for TCP, CP and TCE on December 31, 2011. TCPH did not have employees nor did it pay any compensation prior to January 2012. Accordingly, the historic disclosures regarding compensation found below reflect compensation paid to the named executive officers by TCPH’s subsidiaries.
The following table sets forth compensation paid to each of the individuals who served as the Principal Executive Officer (“PEO”) and “named executive officers” for the Company and our subsidiaries during the fiscal years ended December 31, 2012 and 2011.
Summary Compensation Table
Name and Principal Position* Year Salary
($) Bonus
($) Other Incentive Compen-
sation
($) (1) All Other Compen-
sation
($) (2) Total
($)
Timothy S. Krieger
600,000 14,500 - 15,988 630,488
Chairman of the Board,
240,000 - - 14,705 254,705
Chief Executive Officer &
President, PEO
Wiley H. Sharp III
134,000 - - - 134,000
Vice President - Finance &
- - - - -
Chief Financial Officer (3)
Keith W. Sperbeck
180,000 - - 21,540 201,540
Vice President - Operations &
177,500 24,780 - 18,047 220,327
Secretary
Stephanie E. Staska
136,000 45,000 - 19,325 200,325
Vice President - Risk
130,000 85,000 - 16,874 231,874
Management & Chief Risk
Officer
*The position titles used are the current titles held with TCPH. Ms. Staska and Mr. Sperbeck each formerly held the title of Senior Manager at TCP.
(1)The Company does not have an incentive stock plan, non-equity incentive plan, or non-qualified deferred compensation plan, and consequently, there were no stock awards, option awards, non-equity incentive plan compensation, or non-qualified deferred compensation earnings.
(2)Other compensation consists of health care premiums paid on behalf of the employee and, in the case of Ms. Staska, tuition reimbursement.
(3)Mr. Sharp was hired on March 8, 2012.
Outstanding Equity Awards
The Company does not have an incentive stock plan, non-equity incentive plan, or non-qualified deferred compensation plan, and consequently, there were no stock awards, option awards, non-equity incentive plan compensation, or non-qualified deferred compensation earnings for any of our named executive officers outstanding as of the end of our last completed fiscal year.
Governor Compensation
On July 18, 2012, the Board resolved to provide compensation to board and committee members as follows:
·Each non-employee governor attending board meetings in person - $5,000.
·Each non-employee governor attending a committee meeting in person and serving as chair - $1,500.
·Each non-employee governor attending a committee meeting in person - $1,000.
·Any board or committee meeting attended telephonically reduces fees by one-half.
The Company does not have an incentive stock plan, non-equity incentive plan, or non-qualified deferred compensation plan, or provide retirement benefits for directors. The amount of compensation each current and former director received in 2012, the first year such payments were made, is shown in the table below.
(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.
(3)On October 31, 2012, Mr. Henneman informed the Company of his decision to resign from the board effective immediately. His decision to resign was not due to any disagreement with the Company on any matter relating to the Company’s operations, policies, or practices.
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.
TCPH maintains a 401(k) plan that is tax-qualified for its employees, including its executive officers. The plan does not offer employer matching with the 401(k) plan. However, the 401(k) plan 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 & Consulting 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. Pursuant to this agreement, Mr. Krieger currently receives an annual salary of $600,000. If Mr. Krieger’s employment is terminated for reasons other than cause, he will receive severance pay in an amount equal to one year of his salary. If Mr. Krieger’s employment is terminated for any reason other than non-renewal of his agreement, he is subject to a non-compete agreement for a period of six months. If his employment agreement 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 receive only six months’ salary as severance pay.
Wiley H. Sharp III: On March 8, 2012, TCPH entered into a Consultant and Professional Services Agreement with Wiley H. Sharp III pursuant to which he serves as Vice President - Finance and Chief Financial Officer for TCPH. We pay Mr. Sharp $11,000 per month for these services. In the event that the Acquisition Advisory Agreement with Altus Financial Group, LLC, dated January 5, 2012, as amended, is terminated, then Mr. Sharp’s compensation will be increased to $15,000 per month. See “Acquisition Advisory Agreement” below. The Acquisition Advisory Agreement was terminated by mutual consent effective July 1, 2012. Effective March 1, 2013, the Company and Mr. Sharp extended the Consultant and Professional Services Agreement until May 31, 2013.
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. Under the employment agreement, as amended, Ms. Staska currently receives an annual salary of $150,000. In addition, Ms. Staska will be paid $5,250 annually until such time as her student loans are paid off. 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 of governors 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 bonus on gains posted on their accounts. 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 Energy Trading - Market Risk Management.”
Indemnification of Governors and Executive Officers and Limitations of Liability
Under our member control agreement, 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”). Our member control agreement 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 member control agreement 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 our member control agreement. In the case of an officer or governor, the determination shall be made (1) by the board of governors 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.
Our member control agreement 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 our member control agreement.
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
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 29, 2013 for: (a) each director; (b) the executive officers as set forth in the Summary Compensation Table; and (c) the directors and current executive officers as a group. Unless otherwise indicated, each person has sole investment and voting power (or shares such powers with his or her spouse) with respect to the shares set forth in the following table.
(1)Pursuant to a Membership Unit Purchase Agreement dated December 31, 2012, Mr. Krieger purchased the 525 units held by DBJ 2001 Holdings, LLC, which is controlled by Mr. Johnson.
(2)Pursuant to a Membership Unit Purchase Agreement, dated December 30, 2011, as amended, TCPH redeemed the financial rights of the 1,540 units owned by Mr. Tufte effective January 1, 2012.
Item 13
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 2012. 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 interests, or any member of the immediate family of any of the foregoing, had or will have a direct or indirect material interest.
Related Party Loans
On July 16, 2009, TCP borrowed $2,000,000 from Patrick C. Sunseri. Prior to January 1, 2010, Mr. Sunseri was one of four non-voting special class members of TCP as well as an employee of TCP. TCP redeemed the non-voting interests on January 1, 2010 and those former members received distributions of the balances of their capital accounts in February 2010. Mr. Sunseri remains employed with TCP as an energy trader and manager. The note is payable upon demand and is secured by all cash, accounts receivable, and other assets of TCP. It bears interest at the rate of 15% per annum. The outstanding balance as of March 2, 2013 on the note is $166,667. Timothy Krieger, our CEO, and Michael Tufte, the former president of TCE and the former owner of approximately 24% of our outstanding units, have each signed personal guarantees for this debt.
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 under “Reorganization”, 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, we 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 this payment obligation does not apply to any transaction entered into on or after January 1, 2015.
Acquisition Advisory Agreement
On January 5, 2012, we entered into an Acquisition Advisory Agreement with Altus Financial Group LLC, of which Wiley H. Sharp III, our Vice President - Finance and CFO, is a 50% partner. Pursuant to this agreement, Altus Financial Group LLC has agreed to research and identify acquisition candidates within the retail electricity industry, provide general data and a comparative analysis on these companies; contact and solicit targeted companies for indications of interest in selling; analyze and assess acquisition candidates; provide us with Altus’ opinion as to the value of certain of the equity interests or assets of targets (the “Assets”); assist us in connection with the formation of one or more entities (each, a “Newco”) to effect the purchase of Assets, including the preparation of appropriate financial models; advise and assist us in obtaining appropriate and acceptable financing for Newco (the “Financing”); advise and assist us and our legal counsel in connection with the structure, preparation, delivery, and negotiation of one or more offers by Newco to purchase the Assets (the “Acquisitions”); and advise and assist us on all other transaction-related matters. In exchange for the foregoing services, the agreement calls for the payment of a monthly retainer of $15,000, plus the payment of placement fees, in an amount to be mutually agreed upon based upon the nature of the Financing required. At the closing of any Acquisition, we are also required to deliver 10.00% of the equity interests of the applicable Newco to Altus, or its designee. If we decide, in our sole discretion, not to form a Newco, we must pay a success fee to Altus of 2.5% of the total consideration paid at the closing for the Acquisition. We also reimburse Altus on a monthly basis for all out-of-pocket and incidental costs and expenses incurred.
This agreement was amended effective March 6, 2012, in connection with Mr. Sharp joining the Company. The amendment extended the agreement for an indefinite term, subject to termination with or without cause by either party upon 10 days’ prior written notice, and modified the provision regarding delivery of equity interests. The agreement was terminated by mutual consent effective July 1, 2012.
Real Estate Leases
The Company is subject to a lease with Kenyon Holdings, LLC (“Kenyon”) for the office space under lease in Lakeville, Minnesota. Kenyon, which is owned by Timothy S. Krieger, CEO, and Keith W. Sperbeck, Vice President - Operations, purchased that building on June 23, 2011. Effective January 1, 2013, the Company entered into a new lease with Kenyon at what it believes to be market rates. Under the lease, which is for 11,910 square feet, the Company is required to pay base rent of $12,264, as well as estimated real estate taxes and operating expenses for 2013 of $7,275 for an approximate total of $19,539 per month.
The Company is subject to a lease with the Brandon J. and Heather N. Day Revocable Trust (the “Day Trust”) for 1,800 square feet of office space in Tulsa, Oklahoma at what it believes to be market rates. Brandon Day is the Vice President and an employee of CEF. The lease commenced on March, 1, 2013 for a 36 month term at a monthly rent of $3,750.
Item 14
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 2012 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 2012 and 2011, the review of the Company’s interim consolidated financial statements for the first, second, and third quarters in 2012, and for audit-related, tax, and other services performed in 2012 and 2011.
(1)“Audit fees” includes the annual audits of the Company’s consolidated financial statements, reviews of interim consolidated financial statements included on Form 10-Q for the first, second and third quarters of 2012, consultation on matters related to financial reporting, and consents for securities offerings.
(2)“Audit-related fees” includes fees billed for assurance and related services that are reasonably related to the performance of audits or reviews of financial statements and are not reported under "Audit fees", such as consultation for Form S-1 registration.
(3)“Tax fees” include fees billed for professional services rendered for tax returns ($41,172 in 2012 and $27,300 in 2011) and tax advice and planning ($50,465 in 2012 and $23,150 in 2011).
(4)“Other fees” includes fees billed for services provided other than the services described above such as miscellaneous research projects and consultation in regard to the cessation of Canadian operations.
Audit Committee Pre-Approval Policies
For fiscal years beginning after January 1, 2013, our audit committee has adopted pre-approval policies and procedures pursuant to which audit, audit-related, tax services, and all permissible non-audit services, are pre-approved by category of service. The fees are budgeted, and actual fees versus the budgeted amounts are monitored throughout the year.
During the year, circumstances may arise when it may become necessary to engage the independent auditor for additional services not contemplated in the original pre-approval. In those instances, we will obtain the specific pre-approval of the audit committee before engaging the independent auditor. The policies require 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 2012, the appointment of Baker Tilly Virchow Krause as Independent Registered Public Accountants was approved by the Board of Governors.
Part IV
Item 15
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)
4.1
Form of Indenture (incorporated by reference 4.1 to the Registrant’s Form S-1/A filed March 30, 2012)
4.2
Form of Notes (included as Exhibit A to the Indenture filed as Exhibit 4.1 to the Registrant’s Form S-1/A filed March 30, 2012)
4.3
Form of Note Confirmation (incorporated by reference to Exhibit 4.3 to the Registrant’s Form S-1/A filed May 7, 2012)
4.4(i)
Form of Subscription Agreement (incorporated by reference to Exhibit 4.3 to the Registrant’s Form S-1/A filed May 7, 2012)
4.4(ii)
Form of Subscription Agreement for investors from states with suitability standards (incorporated by reference to Exhibit 4.3 to the Registrant’s Form S-1/A filed May 7, 2012)
4.5
Paying Agent Agreement (incorporated by reference to Exhibit 4.1 to the Registrant’s Form S-1/A filed March 30, 2012)
10.1
Employment Agreement between the Company and Timothy Krieger (*) (incorporated by reference to Exhibit 10.1 to the Registrant’s Form S-1 filed February 10, 2012)
10.2
Employment Agreement between the Company and Keith Sperbeck (*) (incorporated by reference to Exhibit 10.2 to the Registrant’s Form S-1 filed February 10, 2012)
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)
Exhibit Number
Description
10.4
Second Amendment to Employment Agreement dated December 31, 2012 between Twin Cities Power Holdings, LLC and Stephanie Staska (*) (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed March 18, 2013)
10.5
Membership Unit Purchase Agreement between the Company and Michael Tufte (incorporated by reference to Exhibit 10.4 to the Registrant’s Form S-1/A filed March 30, 2012)
10.6
Form of Indemnification Agreement between the Company and each of Timothy Krieger, David Johnson, Wiley H. Sharp III, Keith Sperbeck, Stephanie Staska, Mark Cohn, and William M. Goblirsch (incorporated by reference to Exhibit 10.5 to the Registrant’s Form S-1 filed February 10, 2012)
10.7
Outsourcing Agreement, dated , 2012, between the Company and Redwater LLC (incorporated by reference to Exhibit 10.6 to the Registrant’s Form S-1/A filed May 7, 2012)
10.8
Office Lease, dated January 1, 2013 between Twin Cities Power Holdings, LLC and Kenyon Holdings, LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed March 18, 2013)
10.9
Promissory Note, dated October 1, 2011, payable to Robert O. Schachter, HTS Capital, LLC and Clearwaters Capital, LLC (incorporated by reference to Exhibit 10.8 to the Registrant’s Form S-1 filed February 10, 2012)
10.10
Promissory Note, dated January 1, 2012, payable to Michael Tufte (incorporated by reference to Exhibit 10.9 to the Registrant’s Form S-1 filed February 10, 2012)
10.11
Loan Agreement, dated September 1, 2006, payable to John Hanson (incorporated by reference to Exhibit 10.10 to the Registrant’s Form S-1 filed February 10, 2012)
10.12
Loan Agreement, dated April 1, 2008, payable to John Hanson (incorporated by reference to Exhibit 10.11 to the Registrant’s Form S-1 filed February 10, 2012)
10.13
Note Payable, dated April 8, 2011, payable to John Hanson (incorporated by reference to Exhibit 10.12 to the Registrant’s Form S-1 filed February 10, 2012)
10.14
Promissory Note Extension dated on or around December 10, 2012 between John O. Hanson and Twin Cities Power, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed March 18, 2013)
10.15
Loan Agreement, dated July 16, 2009, payable to Patrick Sunseri (incorporated by reference to Exhibit 10.13 to the Registrant’s Form S-1 filed February 10, 2012)
10.16
Acquisition Advisory Agreement, dated January 5, 2012, between Twin Cities Power, L.L.C. and Altus Financial Group LLC (incorporated by reference to Exhibit 10.14 to the Registrant’s Form S-1 filed February 10, 2012)
10.17
Joinder Agreement, dated December 23, 2011, and underlying Assignment of Financial Rights Agreements, each dated January 1, 2010 (incorporated by reference to Exhibit 10.15 to the Registrant’s Form S-1 filed February 10, 2012)
10.18
Form of Trader Employment Agreement (incorporated by reference to Exhibit 10.16 to the Registrant’s Form S-1 filed February 10, 2012)
Exhibit Number
Description
10.19
Corporate Guaranty, dated December 29, 2011, by the Company in favor of Midwest Independent Transmission System Operator, Inc. (incorporated by reference to Exhibit 10.17 to the Registrant’s Form S-1 filed February 10, 2012)
10.20
Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Summit Energy, LLC) (incorporated by reference to Exhibit 10.18 to the Registrant’s Form S-1 filed February 10, 2012)
10.21
Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Twin Cities Energy, LLC) (incorporated by reference to Exhibit 10.19 to the Registrant’s Form S-1 filed February 10, 2012)
10.22
Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for TC Energy Trading, LLC) (incorporated by reference to Exhibit 10.20 to the Registrant’s Form S-1 filed February 10, 2012)
10.23
Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Twin Cities Power, LLC) (incorporated by reference to Exhibit 10.21 to the Registrant’s Form S-1 filed February 10, 2012)
10.24
Guaranty, dated December 27, 2011, by the Company in favor of PJM Settlement, Inc. (for Cygnus Energy Futures, LLC) (incorporated by reference to Exhibit 10.22 to the Registrant’s Form S-1 filed February 10, 2012)
10.25
Consultant and Professional Services Agreement, dated March 8, 2012, between TCPH and Wiley H. Sharp III (*) (incorporated by reference to Exhibit 10.23 to the Registrant’s Form S-1/A filed March 30, 2012)
10.26
First Amendment to Consultant and Professional Services Agreement effective March 1, 2013 between Twin Cities Power Holdings, LLC and Wiley H. Sharp III (*) (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed March 18, 2013)
10.27
Futures Risk-Based Margin Finance Agreement, dated January 2, 2012, between CEF and ABN AMRO (incorporated by reference to Exhibit 10.24 to the Registrant’s Form S-1/A filed March 30, 2012)
10.28
Addendum to Promissory Note payable to Robert O. Schachter, HTS Capital, LLC and Clearwaters Capital, LLC (incorporated by reference to Exhibit 10.25 to the Registrant’s Form S-1/A filed March 30, 2012)
10.29
Membership Unit Purchase Agreement, dated March 28, 2012, between Twin Cities Power, L.L.C. and John Hanson (incorporated by reference to Exhibit 10.26 to the Registrant’s Form S-1/A filed March 30, 2012)
10.30
Assignment of Membership Unit Purchase Agreement, effective July 1, 2012 (incorporated by reference Exhibit 10.1 to the Registrant’s Form 10-Q filed November 14, 2012)
10.31
First Amendment to Loan Documents between Patrick C. Sunseri and Twin Cities Power, LLC dated as of May 14, 2012 (incorporated by reference Exhibit 10.1 to the Registrant’s Form 10-Q filed June 25, 2012)
10.32
Agreement dated as of May 22, 2012 between Katmando Holdings Inc. and Twin Cities Power Holdings, LLC (incorporated by reference Exhibit 10.2 to the Registrant’s Form 10-Q filed June 25, 2012)
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.
TWIN CITIES POWER HOLDINGS, LLC
Dated: March 29, 2013
By:
/s/ Timothy S. Krieger
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:
Dated: March 29, 2013
/s/ Timothy S. Krieger
Timothy S. Krieger
Chief Executive Officer, President and Chairman of the Board (principal executive officer)
Dated: March 29, 2013
/s/ Wiley H. Sharp III
Wiley H. Sharp III
Vice President - Finance and Chief Financial Officer (principal accounting and financial officer)
Dated: March 29, 2013
/s/ Mark A. Cohn
Mark A. Cohn
Governor
Dated: March 29, 2013
/s/ William M. Goblirsch
William M. Goblirsch
Governor
Dated: March 29, 2013
/s/ David B. Johnson
David B. Johnson
Governor