ASPIRITY HOLDINGS LLC - FORM 10-Q

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - ASPIRITY HOLDINGS LLC	Financial_Report.xls
EX-31.2 - CERTIFICATION - ASPIRITY HOLDINGS LLC	twincities_10q-ex3102.htm
EX-32.1 - CERTIFICATION - ASPIRITY HOLDINGS LLC	twincities_10q-ex3201.htm
EX-31.1 - CERTIFICATION - ASPIRITY HOLDINGS LLC	twincities_10q-ex3101.htm
EX-10.4 - ASSIGNMENT OF EMPLOYMENT AGREEMENT - ASPIRITY HOLDINGS LLC	twincities_10q-ex1004.htm

UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2015

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

For the Transition Period from __ to __

Commission File Number: 333-179460

Twin Cities Power Holdings, LLC

(Exact name of registrant as specified in its charter)

Minnesota		6221 – Commodity Contracts Brokers and Dealers		27-1658449
(State of organization)		(Primary Standard Industrial Classification Code Number)		(IRS Employer Identification Number)

	16233 Kenyon Avenue, Suite 210 Lakeville, Minnesota 55044
	(Address of principal executive offices, zip code)

	(952) 241-3103
	(Registrant’s telephone number, including area code)

	not applicable
	(Former name, former address and former fiscal year, if changed since last report)

_________________________________________________________

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or smaller reporting company. See definition of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer o

Smaller reporting company x

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

TABLE OF CONTENTS

Definitions	3
Forward Looking Statements	8
Non-GAAP Financial Measures	9
Part I – Financial Information	10
Item 1 - Financial Statements (Unaudited)	10
Consolidated Balance Sheets	10
Consolidated Statements of Comprehensive Income	11
Consolidated Statements of Cash Flows	12
Notes to Consolidated Financial Statements	14
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Industry Background	37
Company Overview	42
Results of Operations	46
Liquidity, Capital Resources, and Cash Flow	51
Financing	54
Non-GAAP Financial Measures	56
Critical Accounting Policies and Estimates	56
Item 3 - Quantitative and Qualitative Disclosures about Market Risk	58
Commodity Price Risk	58
Interest Rate Risk	60
Liquidity Risk	60
Wholesale Counterparty Credit Risk	60
Retail Customer Credit Risk	60
Foreign Exchange Risk	60
Item 4 - Controls and Procedures	61
Part II – Other Information	62
Item 1 - Legal Proceedings	62
Item 1A - Risk Factors	62
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 3 - Defaults Upon Senior Securities	62
Item 4 - Mine Safety Disclosures	62
Item 5 - Other Information	62
Item 6 - Exhibits	63
Signatures	64

Definitions

Abbreviation or acronym		Definition
ABN AMRO		ABN AMRO Clearing Chicago, LLC and ABN AMRO Clearing Bank, N.V.
AESO		Alberta Electric System Operator, a statutory corporation of the Province of Alberta, is an ISO serving the Alberta Interconnected Electric System
AOCI		Accumulated other comprehensive income
Apollo		Apollo Energy Services, LLC, a wholly-owned, first-tier subsidiary of TCPH
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
BLS		Bureau of Labor Statistics, an agency within the U.S. Department of Labor
Btu; therm; MMBtu		A “Btu” or British thermal unit is a measure of thermal energy or the amount of heat needed to raise the temperature of one pound of water from 39°F to 40°F. A “therm” is one hundred thousand Btu. One “MMBtu” is one million Btu.
C$		Canadian dollars
CEF		Cygnus Energy Futures, LLC, a wholly-owned subsidiary of CP and a second-tier subsidiary of TCPH
CFTC		Commodity Futures Trading Commission, an independent agency of the United States government that regulates futures and option markets
CME		CME Group Inc. operates the CME (Chicago Mercantile Exchange), CBOT (Chicago Board of Trade), NYMEX (New York Mercantile Exchange), and COMEX (Commodities Exchange) derivatives exchanges and also offers certain cleared OTC products and services
Company		TCPH and its subsidiaries
CoV		Abbreviates the coefficient of variation, a simple measure of volatility useful for comparing two or more data series; equal to the standard deviation divided by the mean
CP		Cygnus Partners, LLC, a wholly-owned, first-tier subsidiary of TCPH
CP&U		Community Power & Utility, LLC, an electricity retailer acquired by TCP on June 29, 2012
CSE		Comparison shopping engine, a web site that compares prices for specific products. While most comparison shopping engines do not offer the products or services themselves, some may earn commissions when users follow the links in the search results and make a purchase from an online vendor
CTG		Chesapeake Trading Group, LLC, a wholly-owned subsidiary of TCPH, effective April 30, 2015
Cyclone		Cyclone Partners, LLC, a wholly-owned, first-tier subsidiary of TCPH

Abbreviation or acronym		Definition
Degree-days; CDD; HDD		A “degree-day” compares outdoor temperatures to a standard of 65°F. Hot days require energy for cooling and are measured in cooling degree-days or “CDD” while cold days require energy for heating and are measured in heating degree-days or “HDD”. For example, a day with a mean temperature of 80°F would result in 15 CDD and a day with a mean temperature of 40°F would result in 25 HDD. If heating degree-days are less than the average for an area for a period, the weather was “warmer than normal”; if they were greater, it was “colder than normal”. The converse is true for cooling degree-days - if CDD are less than the average for an area for a period, the weather was “colder than normal”; if they were greater, it was “warmer than normal”.
DOE		U.S. Department of Energy
EDC; LDC		Electric distribution company; may also be known as a local distribution company
EIA		Energy Information Administration, an independent agency within DOE
ERCOT		Electric Reliability Council of Texas, an ISO managing 85% of the electric Load of Texas and subject to oversight by the Public Utility Commission of Texas and the Texas Legislature but not FERC
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission, an independent regulatory agency within DOE
Form S-1		The Company’s Registration Statement on Form S-1, declared effective by the Securities and Exchange Commission on May 10, 2012 with respect to the Company’s Notes Offering
FTR		Financial Transmission Rights are financial instruments traded in certain ISOs and RTOs that entitle their holders to receive or pay charges based on congestion price differences in the day-ahead energy market across specific transmission paths. The value of an FTR reflects the difference in congestion prices rather than the difference in locational marginal prices, which includes energy, congestion, and marginal losses. FTRs are specified between any two pricing nodes on the system, including hubs, control zones, aggregates, generator buses, load buses and interface pricing points. FTRs are generally available in increments of 0.1 MW and for periods ranging from 1 month to multiple years. The value of an FTR can be positive or negative depending on the sink minus source congestion price difference, with a negative differences resulting in liability for the holder.
GAAP		Generally accepted accounting principles in the United States
ICE		InterContinental Exchange Group, Inc. operates a network of 17 regulated exchanges and 6 clearinghouses for financial and commodity markets in the U.S., Canada, Europe, and Asia. In November 2013, ICE completed the acquisition of NYSE Euronext.
INC and DEC		An increment offer or “INC” is an offer in the day-ahead market to sell energy at a specified source bus. An INC will clear if the LMP at the bus equals or exceeds the offer price. A decrement bid or “DEC” is a bid in the day-ahead market to purchase energy at a specified sink bus. A DEC will clear if the LMP at the bus does not exceed the bid price.

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

Abbreviation or acronym		Definition
Notes		The Company’s Renewable Unsecured Subordinated Notes issued pursuant to its ongoing Notes Offering
Notes Offering		The direct public offering the Company’s Notes pursuant to a registration statement on Form S-1 declared effective by the SEC on May 10, 2012
NRSRO		A SEC-recognized Nationally Recognized Statistical Rating Organization; The major NRSROs that rate utilities are Standard & Poor’s Financial Services LLC (“S&P”), Moody’s Investor Services, Inc. (“Moody’s”), and Fitch Ratings Inc. (“Fitch”)
NYISO		New York Independent System Operator, an ISO serving New York state
OTC		Over-the-counter
PJM		PJM Interconnection, a RTO serving all or part of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.
POR; non-POR		All states with restructured retail markets have implemented laws and regulations with respect to permitted billing, credit, and collections practices. Some of these states require an EDC billing customers in their service territory on behalf of suppliers operating there to purchase the receivables generated as a result of energy sales, generally at a modest discount to reflect bad debt experience. These states are known as “purchase of receivables” or “POR” jurisdictions while those without this provision are known as “non-POR” areas.
PURPA		Public Utilities Regulatory Policy Act of 1978
RECs		Renewable energy certificates represent the property rights to the environmental, social, and other non-power qualities of renewable electricity generation and can be sold separately from the underlying physical electricity.
REH		Retail Energy Holdings, LLC, a wholly-owned, first-tier subsidiary of TCPH
SEC		U.S. Securities and Exchange Commission, an independent agency of the United States government with primary responsibility for enforcing federal securities laws and regulating the securities industry and stock exchanges
SUM		Summit Energy, LLC, a wholly-owned subsidiary of TCP and a second-tier subsidiary of TCPH
TCE		Twin Cities Energy, LLC, an inactive, wholly-owned, first-tier subsidiary of TCPH
TCP		Twin Cities Power, LLC, a wholly-owned, first-tier subsidiary of TCPH
TCPC		Twin Cities Power – Canada, Ltd., an inactive, wholly-owned subsidiary of TCE and a second-tier subsidiary of TCPH
TCPH		Twin Cities Power Holdings, LLC
TSE		Town Square Energy, initially, an accounting division of TCP resulting from the acquisition of the business and assets of CP&U. Effective June 1, 2013, TSE became a wholly-owned first-tier subsidiary of the Company and on October 25, 2013, it became a wholly owned subsidiary of REH and a second-tier subsidiary of TCPH

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

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

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

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

Forward Looking Statements

Readers are urged to carefully review and consider the various disclosures made by us in this Form 10-Q and in our other reports filed with the SEC that attempt to advise interested parties of the factors that may affect our business.

Statements in this report that are not statements of historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. Any statements that express, or involve discussions as to, future expectations, risks, beliefs, plans, objectives, assumptions, events, uncertainties, financial performance, or growth strategies, often, but not always, through the use of words or phrases such as “anticipates”, “believes”, “estimates”, “expects”, “intends”, “plans”, “projects”, “likely”, “will continue”, “could”, “may”, “potential”, “target”, “outlook”, or words of similar meaning are not statements of historical facts and may be forward-looking.

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause our actual results to differ materially from those indicated in forward-looking statements made by or on behalf of the Company in this Form 10-Q, in presentations, on our website, in response to questions, or otherwise. You should not place undue reliance on any forward-looking statement. Examples of forward-looking statements include, among others, statements we make regarding:

Expected operating results, such as revenue growth and earnings;

Anticipated levels of capital expenditures and expansion of our retail electricity business segment;

Current or future price volatility in the energy markets and future market conditions;

Our belief that we have sufficient liquidity to fund our operations during the next 12 months;

Expectations of the effect on our financial condition of claims, litigation, environmental costs, contingent liabilities, and governmental and regulatory investigations and proceedings;

Our strategies for risk management; and

Any other risk factors listed from time to time by the Company in reports filed with the Securities and Exchange Commission.

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.

Additional disclosures regarding factors that could cause our results and performance to differ from results or performance anticipated by this report are discussed under the heading “Item 1A – Risk Factors” of our Form 10-K for 2014 (the “2014 Form 10-K”), the “Risk Factors” section beginning on page 10 of our Form S-1, and any assumptions and other factors referred to specifically in connection with such forward-looking statements that could cause our actual results to differ materially from those indicated in the forward-looking statements.

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 “total liquid assets”. The most comparable GAAP measure is total current assets. The Company’s management believes that this non-GAAP financial measure provides useful information to investors and enables investors and analysts to more accurately compare the Company's ongoing financial performance over the periods presented.

Part I – Financial Information

Item 1 - Financial Statements (Unaudited)

Twin Cities Power Holdings, LLC and Subsidiaries

Consolidated Balance Sheets

As of March 31, 2015 and December 31, 2014

	March 31,			December 31,
	2015			2014
	Unaudited
Assets

Current assets
Cash - unrestricted	$	4,396,005		$	2,397,300
Cash in trading accounts		16,003,961			21,099,652
Accounts receivable - trade		5,571,805			2,394,246
Marketable securities		2,579,875			311,586
Prepaid expenses and other current assets		284,544			416,419
Total current assets		28,836,190			26,619,203

Property, equipment ,and furniture, net		846,223			762,529

Other assets
Intangible assets, net		192,103			269,149
Deferred financing costs, net		245,624			241,744
Cash - restricted		1,319,371			1,319,371
Land held for development		1,642,143			953,462
Investment in convertible notes		1,642,380			1,604,879
Total assets	$	34,724,034		$	31,770,337

Liabilities and Members' (Deficit) Equity

Current liabilities
Current portions of debt
Revolver	$	2,754,814		$	1,105,259
Senior notes		789,541			312,068
Renewable unsecured subordinated notes		8,102,083			7,234,559
Accounts payable - trade		2,706,078			1,544,103
Accrued expenses		946,095			681,995
Accrued compensation		4,505,677			3,601,282
Accrued distributions		45,756			–
Accrued interest		1,031,457			849,913
Obligations under settlement agreement		582,565			582,565
Total current liabilities		21,464,066			15,911,744

Long-term liabilities
Senior notes		215,617			217,451
Renewable unsecured subordinated notes		11,375,618			10,418,569
Obligations under settlement agreement		2,330,260			2,524,448
Total liabilities		35,385,561			29,072,212

Commitments and contingencies

Members' (deficit) equity
Series A preferred equity		2,745,000			2,745,000
Common equity		(3,955,265	)		(193,624	)
Accumulated other comprehensive income		548,738			146,749
Total members' (deficit) equity		(661,527	)		2,698,125
Total liabilities and members' (deficit) equity	$	34,724,034		$	31,770,337

See notes to consolidated financial statements.

Twin Cities Power Holdings, LLC and Subsidiaries

Consolidated Statements of Comprehensive Income

Three Months ended March 31, 2015 and 2014

	Three Months
	Ended March 31,
	2015			2014
	Unaudited			Unaudited
Revenue
Wholesale trading revenue, net	$	10,849,696		$	27,021,725
Retail electricity revenue		5,377,109			2,912,526
		16,226,805			29,934,251

Costs and expenses
Cost of retail electricity sold		6,223,221			4,602,217
Retail sales and marketing		245,899			128,442
Compensation and benefits		6,196,239			11,040,699
Professional fees		586,380			727,322
Other general and administrative		1,236,065			904,327
Trading tools and subscriptions		327,305			219,206
		14,815,109			17,622,213

Operating income		1,411,696			12,312,038

Other income (expense)
Interest expense		(764,013	)		(467,765	)
Interest income		49,285			12,150
Gain on foreign currency exchange		95,273			368
Other income		40,387			–
		(579,068	)		(455,247	)

Net income		832,628			11,856,791
Distributions - preferred		(137,268	)		(137,268	)

Net income attributable to common		695,360			11,719,523

Comprehensive income (loss)
Net income		832,628			11,856,791
Foreign currency translation adjustment		(51,270	)		(75,182	)
Change in fair value of cash flow hedges		440,984			(38,135	)
Unrealized gain on securities		12,275			11,875

Comprehensive income	$	1,234,617		$	11,755,349

See notes to consolidated financial statements.

Twin Cities Power Holdings, LLC and Subsidiaries

Consolidated Statements of Cash Flows

Three Months Ended March 31, 2015 and 2014

	Three Months
	Ended March 31,
	2015			2014
	Unaudited			Unaudited
Cash flows from operating activities
Net income	$	832,628		$	11,856,791
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		164,909			220,283
(Increase) decrease in:
Trading accounts and deposits		5,510,942			(8,304,821	)
Accounts receivable		(3,177,559	)		(1,504,740	)
Prepaid expenses and other current assets		131,875			(17,288	)
Increase (decrease) in:
Accounts payable - trade		1,161,975			(4,920	)
Accrued expenses		264,100			52,300
Accrued compensation		904,395			9,362,620
Accrued interest		181,544			165,269
Obligations under settlement agreement		(194,188	)		–
Net cash provided by operating activities		5,780,621			11,825,494

Cash flows from investing activities
Repayment of note receivable		–			140,964
Purchase of marketable securities		(2,256,014	)		(750,715	)
Purchase of convertible promissory note		(37,501	)		(1,003,056	)
Purchase of property, equipment, and furniture		(124,859	)		(25,163	)
Purchase of land held for development		(211,295	)		(22,279	)
Increase in restricted cash		–			(1,319,371	)
Acquisition of Discount Energy Group, LLC		–			(680,017	)
Net cash used in investing activities		(2,629,669	)		(3,659,637	)

Cash flows from financing activities
Deferred financing costs		(50,579	)		–
Payments on senior notes		(1,747	)		(200,000	)
Proceeds from revolver		4,884,000			–
Payments on revolver		(3,234,445	)		–
Payment of obligations under non-competition agreement		–			(62,500	)
Issuance of renewable unsecured subordinated notes		2,541,679			1,939,561
Redemption of renewable unsecured subordinated notes		(717,106	)		(136,666	)
Distributions - preferred		(91,512	)		(137,268	)
Distributions - common		(4,457,000	)		(1,401,080	)
Net cash provided by (used in) financing activities		(1,126,710	)		2,047

Net increase in cash		2,024,242			8,167,904

Effect of exchange rate changes on cash		(25,537	)		(75,180	)

Cash - unrestricted
Beginning of period		2,397,300			3,190,495
End of period	$	4,396,005		$	11,283,219

See notes to consolidated financial statements.

Twin Cities Power Holdings, LLC and Subsidiaries

Consolidated Statements of Cash Flows (Continued)

Three Months Ended March 31, 2015 and 2014

	Three Months
	Ended March 31,
	2015			2014
	Unaudited			Unaudited
Non-cash investing and financing activities:
Effective portion of cash flow hedges	$	(422,424	)	$	318,479

Accrued distributions - preferred	$	45,756		$	–

Acquisition of land for development via assignment and assumption agreement	$	477,386		$	–

Unrealized gain on investment securities	$	12,275		$	11,875

Supplemental disclosures of cash flow information:
Cash payments for interest	$	596,595		$	302,496
Capitalized interest related to land held for development	$	5,255		$	–

See notes to consolidated financial statements.

Twin Cities Power Holdings, LLC and Subsidiaries

Notes to Consolidated Financial Statements

Basis of Presentation and Description of Business

Basis of Presentation

Twin Cities Power Holdings, LLC (“TCPH” or the “Company”) has prepared the foregoing unaudited consolidated financial statements in accordance with GAAP and the requirements of the SEC with respect to interim reporting. As permitted under these rules, certain footnotes and other financial information required by GAAP for complete financial statements have been condensed or omitted. The interim consolidated financial statements include all normal and recurring adjustments that are necessary for a fair presentation of our financial position and operating results and include the accounts of TCPH and its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

For additional information, please refer to our audited consolidated financial statements and the accompanying notes for the years ended December 31, 2014 and 2013 included in our 2014 Form 10-K.

Businesses

TCPH is a Minnesota limited liability company formed on December 30, 2009. On November 14, 2011, TCPH entered into an Agreement and Plan of Reorganization (the “Reorganization”) with its then current members and Twin Cities Power, LLC (“TCP”), Cygnus Partners, LLC (“CP”), and Twin Cities Energy, LLC (“TCE”) which were affiliated through common ownership. Effective December 31, 2011, following receipt of approval from the Federal Energy Regulatory Commission (“FERC”), the members of TCP, CP, and TCE each contributed all of their ownership interests in these entities to TCPH in exchange for ownership interests in TCPH, which made TCPH a holding company and the sole member of each of TCP, CP, and TCE. The Reorganization was accounted for as a transaction among entities under common control.

Subsequent to the Reorganization, the Company formed two active first-tier subsidiaries, Retail Energy Holdings, LLC (“REH”) and Cyclone Partners LLC (“Cyclone”) and TCE and its wholly-owned subsidiary, Twin Cities Power – Canada, Ltd., became inactive. On October 27, 2014, the Company formed Apollo Energy Services, LLC (“Apollo”) as a wholly-owned subsidiary for the purpose of providing centralized services to the Company’s various other subsidiaries. Substantially all of the management rights and certain of the direct employees of TCPH were transferred to Apollo as of January 1, 2015.

With respect to active second-tier subsidiaries, as of March 31, 2015, TCP had two, Summit Energy, LLC (“SUM”) and Chesapeake Trading Group, LLC (“CTG”); CP had one, Cygnus Energy Futures, LLC (“CEF”); and REH had three, Town Square Energy, LLC (“TSE”), Town Square Energy East, LLC (“TSEE” formerly known as Discount Energy Group, LLC or “DEG”), and Town Square Energy Canada, Ltd. (“TSEC”).

Through its subsidiaries, the Company trades electricity in North American wholesale markets, provides electricity supply services to retail customers in certain states that permit retail choice, and engages in certain investment and real estate development activities. Consequently, we have three major business segments used to measure our activity – wholesale trading, retail energy services, and diversified investments.

Wholesale Trading

The Company trades contracts in wholesale electricity markets managed by Independent System Operators or Regional Transmission Organizations (collectively, the “ISOs”) and regulated by FERC, including those managed by the Midcontinent Independent System Operator (“MISO”), the PJM Interconnection (“PJM”), ISO New England (“ISO-NE”), and the New York Independent System Operator (“NYISO”). We also are members of the Electric Reliability Council of Texas (“ERCOT”) which is an ISO regulated by the Texas Public Utilities Commission and the Texas Legislature. The Company also trades electricity and other energy-related commodities and derivatives on exchanges operated by the Intercontinental Exchange® (“ICE”), the Natural Gas Exchange Inc. (“NGX”), and the CME Group (“CME”), all of which are regulated the Commodity Futures Trading Commission (“CFTC”).

Retail Energy Services

On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC, a retail energy supplier serving residential and small commercial markets in Connecticut. The business was re-named TSE, and beginning on July 1, 2012, the Company began selling electricity to retail accounts. Initially, TSE was run as a division of TCP but effective June 1, 2013, TSE was reorganized as a wholly-owned subsidiary of the Company. During late 2012 and early 2013, TSE applied for retail electricity supplier licenses for the states of Massachusetts, New Hampshire, and Rhode Island which were issued on various dates in 2013.

On October 25, 2013, in anticipation of receipt of FERC approval of the Company’s acquisition of TSEE formerly known as DEG, a retail energy business licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio, the Company formed REH and transferred the ownership of TSE to this entity. FERC approval of the acquisition was received on December 13, 2013 and the transaction closed on January 2, 2014. Consequently, the retail markets in which the Company competes include: Connecticut, Maryland, Massachusetts, New Hampshire, New Jersey, Pennsylvania, Ohio, and Rhode Island.

Diversified Investments

On October 23, 2013, the Company formed Cyclone as a wholly-owned subsidiary to take advantage of certain investment opportunities present in the residential real estate market. Specifically, Cyclone acquires and develops land for resale, either as improved sites for construction of single- and multi-family homes or as completed dwellings. In addition to real estate investments, the Company’s diversified investments segment includes certain securities issued by privately-held companies.

Summary of Significant Accounting Policies

A description of our significant accounting policies is included in the 2014 Form 10-K and our interim consolidated financial statements should be read in conjunction with the financial statements and accompanying notes included in that report.

Results for the three month period ended March 31, 2015 are not necessarily indicative of the results expected for the year ending December 31, 2015.

Cash Equivalents

Cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. As of March 31, 2015 and December 31, 2014, the Company had no cash equivalents.

Reclassifications

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

Revenue Recognition

Wholesale Trading

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

Retail Energy Services

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

Diversified Investments

Derivative Instruments

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

In our retail operations, we are exposed to volatility in the cost of energy acquired for sale to customers, and as a result, we use derivatives to hedge or reduce this variability. We follow ASC 815, Derivatives and Hedging (“ASC 815”) guidance that permits “hedge accounting” under which the effective portion of gains or losses from the derivative and the hedged item are recognized in earnings in the same period. To qualify for hedge accounting, the relationship between the “hedged item” - say power purchases for a given delivery zone - and a derivative used as a “hedging instrument” - say, a swap contract for future delivery of electricity at a related hub - must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis.

For these derivatives “designated” as cash flow hedges, the effective portion of any change in the hedging instrument’s fair value is recorded as other comprehensive income and deferred until the change in value of the hedged item is recognized in earnings. Our risk management policies also permit the use of undesignated derivatives which we refer to as “economic hedges”. For an undesignated economic hedge, all changes in the derivative financial instrument’s fair value are recognized currently in revenues.

“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.

Financial Instruments

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

Foreign Currencies

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

For foreign subsidiaries whose functional currency is the local foreign currency, balance sheet accounts are translated at exchange rates in effect at the end of the month and income statement accounts are translated at average monthly exchange rates for the period. Foreign currency transactions denominated in a foreign currency result in gains and losses due to the increase or decrease in exchange rates between periods. Translation gains and losses are included in accumulated other comprehensive income, as a separate component of equity. Gains and losses from foreign currency transactions are included in other income or expense. Foreign currency transactions resulted in gains of $95,273 and $368 for the three months ended March 31, 2015 and 2014, respectively.

Concentrations of Credit Risk

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

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

Fair Value

The fair values of the Company’s cash, accounts receivable, accounts payable, and revolver were considered to approximate their carrying values at March 31, 2015 and December 31, 2014 due to the short-term nature of the accounts.

Management believes the carrying values of the Company’s Renewable Unsecured Subordinated Notes reasonably approximate their fair values at March 31, 2015 and December 31, 2014 due to the relatively new age of these particular instruments. No assessment of the fair value of these obligations has been completed and there is no readily available market price.

See also “Note 7 – Fair Value Measurements”.

Accounts Receivable

Receivables are reported at the amount management expects to collect from outstanding balances. Differences between amounts due and expected collections are reported in the results of operations for the period in which those differences are determined. Receivables are written off only after collection efforts have failed, and the Company typically does not charge interest on past due accounts. There was no allowance for doubtful accounts as of March 31, 2015 and December 31, 2014.

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 8 - Intangible Assets”.

Impairment of Long-Lived Assets

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

Profits Interests

Specific second-tier subsidiaries of the Company have Class B members. Under the terms of the subsidiaries’ member control agreements, Class B members have no voting rights, are not required to contribute capital, and have no rights to distributions following termination of employment, but are entitled to a defined share of profits while employed. Since Class B members have no corporate governance rights or risk of capital loss (or gain), they do not own non-controlling equity interests and profits interests payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the balance sheet.

During the three months ended March 31, 2015 and 2014, the Company included $1,766,527 and $5,186,635, respectively, recorded in compensation and benefits on the consolidated statements of comprehensive income, representing the allocation of profits interests to Class B members.

Income Taxes

The Company and its subsidiaries are not taxable entities for U.S. federal income tax purposes. As such, the Company and its subsidiaries do not directly pay federal income tax. Taxable income or loss, which may vary substantially from the net income or net loss reported in our consolidated statements of comprehensive income, is includable in the federal income tax returns for each member. The holder of the Company’s preferred units is taxed based on distributions received, while holders of common units are taxed on their proportionate share of the Company’s taxable income. Therefore, no provision or liability for federal or state income taxes has been made for those entities.

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

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

The Company’s federal and state tax returns are potentially open to examinations for the years 2011 through 2014 and its Canadian tax returns are potentially open to examination for the years 2011 through 2014.

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

New Accounting Pronouncements

In April 2015, FASB issued a proposal for a one-year deferral of the effective date for Accounting Standards Update 2014-09 Revenue from Contracts with Customers (Topic 606) ("ASU 2014-09"). Originally, in May 2014, the FASB issued new accounting guidance related to revenue recognition. This new standard will eliminate all industry-specific guidance and replace all current U.S. GAAP guidance on the topic. The new revenue recognition standard provides a unified model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration for which the entity expects to be entitled in exchange for those goods or services. The Company was originally required to adopt the standard on January 1, 2017. Subsequently, the FASB proposed a one-year deferral of the effective date for this standard. If the deferral is adopted, the Company would now be required to adopt the standard on January 1, 2018. Early application is not permitted. The update may be applied using one of two methods: retrospective application to each prior reporting period presented, or retrospective application with the cumulative effect of initially applying the update recognized at the date of initial application. We are currently assessing the impact on the Company’s consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835) (“ASU 2015-03”) simplifying the presentation of debt issuance costs. The new guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The recognition and measurement guidance for debt issuance costs are not affected by the new guidance. This guidance is effective for annual and interim periods beginning after December 15, 2015, and early adoption is permitted for financial statements that have not been previously issued. The Company is currently evaluating the impact of ASU 2015-03 on the Company’s consolidated financial position and disclosures.

Cash

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

Restricted cash at March 31, 2015 and December 31, 2014 was $1,319,371. All restricted cash was posted as security in connection with certain litigation in the Canadian courts. See “Note 15 - Commitments and Contingencies”.

Cash held in trading accounts may be unavailable at times for immediate withdrawal depending upon trading activity. Cash needed to meet credit requirements for outstanding trades and that was available for immediate withdrawal as of March 31, 2015 and December 31, 2014 was as follows:

	March 31,		December 31,
	2015		2014
Credit requirement	$	3,691,230	$	6,113,160
Available credit		12,312,731		14,986,492
Cash in trading accounts	$	16,003,961	$	21,099,652

Accounting for Derivatives and Hedging Activities

The following table lists the fair values of the Company’s derivative assets and liabilities as of March 31, 2015 and December 31, 2014:

	Fair Value
	Asset Derivatives		Liability Derivatives
At March 31, 2015
Designated as cash flow hedges:
Energy commodity contracts	$	51,728	$	(474,152	)

Not designated as hedging instruments:
Energy commodity contracts		2,062,643		(2,262,177	)
FTRs		539,838		–
Total derivative instruments		2,654,209		(2,736,329	)
Cash deposits in collateral accounts		16,086,081		–
Cash in trading accounts, net	$	18,740,290	$	(2,736,329	)

At December 31, 2014
Designated as cash flow hedges:
Energy commodity contracts	$	15,732	$	(879,140	)

Not designated as hedging instruments:
Energy commodity contracts		2,350,662		(2,556,862	)
FTRs		1,435,819		–
Total derivative instruments		3,802,213		(3,436,002	)
Cash deposits in collateral accounts		20,733,441		–
Cash in trading accounts, net	$	24,535,654	$	(3,436,002	)

As of March 31, 2015, we had hedged the cost of 45,912 MWh (approximately 25% of expected 2015 electricity purchases for the customers receiving service from us as of that date) and $422,424 of the net loss on the effective portion of the hedge was deferred and included in AOCI. This amount is expected to be reclassified to cost of retail electricity sold by December 31, 2015.

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

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

	Gain (Loss) Recognized in AOCI			Income Statement Classification	Gain (Loss) Reclassified from AOCI
Three Months Ended March 31, 2015
Cash flow hedges	$	(34,624	)	Cost of energy sold	$	(475,608	)

Year Ended December 31, 2014
Cash flow hedges	$	(1,128,514	)	Cost of energy sold	$	91,508

The following table provides details with respect to changes in AOCI as presented in our consolidated balance sheets, including those relating to our designated cash flow hedges, for the period from December 31, 2014 to March 31, 2015:

	Foreign Currency			Cash Flow Hedges			Available for Sale Securities		Total
Balance - December 31, 2014	$	999,041		$	(863,408	)	$	11,116	$	146,749
Other comprehensive income (loss) before reclassifications		(51,270	)		(34,624	)		12,275		(73,619	)
Amounts reclassified from AOCI		–			475,608			–		475,608
Net current period other comprehensive income (loss)		(51,270	)		440,984			12,275		401,989

Balance - March 31, 2015	$	947,771		$	(422,424	)	$	23,391	$	548,738

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.

	March 31,		December 31,
	2015		2014
Wholesale trading	$	1,529,723	$	515,999
Retail energy services - billed		2,529,082		1,158,019
Retail energy services - unbilled		1,513,000		720,228
Accounts receivable - trade	$	5,571,805	$	2,394,246

As of March 31, 2015, there were two accounts, each with a balance greater than 10% of the total, summing to 64% of all receivables - one account in the wholesale segment represented 17% of the total and one in the retail energy services segment equaled 47% of all receivables.

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

The Company believes that any risk associated with these concentrations is minimal.

Marketable Securities

The following table shows the cost and estimated fair value of available-for-sale securities at March 31, 2015 and December 31, 2014:

	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
At March 31, 2015
U.S. equities	$	548,756	$	23,391	$	–	$	572,147
Money market fund		2,007,728		–		–		2,007,728
Total	$	2,556,484	$	23,391	$	–	$	2,579,875

At December 31, 2014
U.S. equities	$	299,836	$	11,116	$	–	$	310,952
Money market fund		634		–		–		634
Total	$	300,470	$	11,116	$	–	$	311,586

For the quarter ended March 31, 2015, the Company had no sales of securities, and recognized no impairment charges.

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

As of March 31, 2015 and December 31, 2014, the Company had no securities that were in an unrealized loss positions.

Fair Value Measurements

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

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

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

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

Financial instruments categorized as Level 1 holdings are publicly traded in liquid markets with daily quotes and include exchange-traded derivatives such as futures contracts and options, certain highly-rated debt obligations, and some equity securities. Holdings such as shares in money market mutual funds that are based on net asset values as derived from quoted prices in active markets of the underlying securities are also classified as Level 1.

The fair values of financial instruments that are not publicly traded in liquid markets, but do have characteristics similar to observable market information such as wholesale commodity prices, interest rates, credit margins, maturities, collateral, and the like upon which valuations are based are categorized in Level 2.

Financial instruments that are not traded in publicly quoted markets or that are acquired based on prices and terms determined by direct negotiation with the issuer are classified as Level 3. Level 3 securities are carried at book value which management believes approximates fair value, until circumstances otherwise dictate while Level 3 derivatives are adjusted to fair value based on appropriate mark-to-model methodologies.

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

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

There have been no changes in the methodologies used since December 31, 2014.

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

	Level 1		Level 2		Level 3		Total
At March 31, 2015
Cash in trading accounts, net	$	15,464,123	$	–	$	–	$	15,464,123
FTR positions, net		–		–		539,838		539,838
Marketable securities		2,579,875		–		–		2,579,875
Investment in convertible notes		–		–		1,642,380		1,642,380

At December 31, 2014
Cash in trading accounts, net	$	19,663,833	$	–	$	–	$	19,663,833
FTR positions, net		–		–		1,435,819		1,435,819
Marketable securities		311,586		–		–		311,586
Investment in convertible notes		–		–		1,604,879		1,604,879

There were no transfers during the three months ended March 31, 2015 between Levels 1 and 2.

Level 3 Assets

The following table reconciles beginning and ending Level 3 fair value financial instrument balances for the three months ended March 31, 2015:

Balance - December 31, 2014	$	3,040,698

Total gains and losses:
Included in other comprehensive income		–
Included in earnings		(895,981	)
Purchases		37,501
Sales		–
Transfers into Level 3		–
Transfers out of Level 3		–
Balance - March 31, 2015	$	2,182,218

Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held as of March 31, 2015	$	(895,981	)

Intangible Assets

On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC (“CP&U”), a retail energy supplier serving residential and small commercial markets in Connecticut, for $160,000. The business has been re-named “Town Square Energy” and is now a wholly-owned second-tier subsidiary of the Company. Of the purchase price, $85,000 was allocated to the acquisition of an existing service contract with an industry-specific provider of transaction management, billing, and customer information software and services, and $75,000 was allocated to customer relationships. The purchase price will be amortized over 36 months using the straight line method.

Effective January 1, 2013, in connection with the sale of his units to Timothy S. Krieger, the Company’s founder, Chairman, Chief Executive Officer, and controlling member, the Company entered into a Non-Competition Agreement (the “NCA”) with David B. Johnson, a current governor of the Company valued at $500,000, to be amortized and paid in equal installments over 24 months.

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

	March 31,			December 31,
	2015			2014
Other intangibles	$	714,658		$	714,658
Non-competition agreement		–			500,000
Less: accumulated amortization		(522,555	)		(945,509	)
Intangible assets, net	$	192,103		$	269,149

Total amortization of intangible assets for the three months ended March 31, 2015 and the year ended December 31, 2014 was $77,046 and $591,487, respectively and is included in other general and administrative expenses.

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. During the three month period ended March 31, 2015 the Company incurred $50,579 in professional fees for the purpose of renewing its public offering. The costs will be amortized when the filing is effective with the SEC.

On October 14, 2014, the Company entered into a credit agreement with a bank and $35,000 of the associated transaction costs were capitalized and will be amortized over 24 months.

	March 31,			December 31,
	2015			2014
Deferred financing costs	$	479,569		$	428,990
Less: accumulated amortization		(233,945	)		(187,246	)
Deferred financing costs	$	245,624		$	241,744

Total amortization of deferred financing costs for the three months ended March 31, 2015 and the year ended December 31, 2014 was $46,699 and $130,815, respectively and is included in other general and administrative expenses.

10.

Land Held for Development; Mortgage Receivable

As of March 31, 2015 and December 31, 2014 land held for development consisted of $1,642,143 and $953,462, respectively.

On January 26, 2015, Cyclone closed on the purchase of a single family home located in New Prague, Minnesota for a price of $198,650, paid in cash. On April 13, 2015, the property was sold to a related party, CEO Tim Krieger, from Cyclone for a price of $197,382.

11.

Convertible Promissory Note

During 2014, the Company invested $1,500,000 in privately placed Series C Convertible Promissory Notes issued by Ultra Green Packaging, Inc. (“Ultra Green”). Ultra Green develops, manufactures, and markets “ecopaper” products made from wheat straw, bamboo, or sugarcane fibers and bioplastic products made from cornstarch. Ultra Green’s ecopaper and bioplastic products are certified as biodegradable and sustainable, and are compostable in about 160 days.

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

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

12.

Debt

Notes payable by the Company are summarized as follows:

	March 31, 2015		December 31, 2014
Demand and Revolving Debt
Payable to ABN AMRO	$	–	$	–
Payable to Royal Bank of Canada		–		–
Revolving note payable to Maple Bank		2,754,814		1,105,259
Subtotal		2,754,814		1,105,259

Term Debt
Mortgage note payable to Security State Bank		222,820		224,568
Mortgage note payable to Lakeview Bank		119,976		119,976
Construction note payable to American Land & Capital		662,362		184,975
Renewable unsecured subordinated notes		19,477,701		17,653,128
Subtotal		20,482,859		18,182,647
Total	$	23,237,673	$	19,287,906

Notes payable by maturity are summarized as follows:

	March 31, 2015		December 31, 2014
Demand and Revolving Debt
Demand	$	–	$	–
2016		2,754,814		1,105,259
Subtotal		2,754,814		1,105,259

Term Debt
2015		7,135,966		7,546,627
2016 to March 31		1,755,658		–
Current maturities		8,891,624		7,546,627

2016 after March 31		2,433,730		–
2016		–		2,648,150
2017		3,047,249		2,869,383
2018		3,302,387		2,642,972
2019		1,223,227		1,213,227
2020 & thereafter		1,584,642		1,262,288
Long term debt		11,591,235		10,636,020
Subtotal		20,482,859		18,182,647
Total	$	23,237,673	$	19,287,906

ABN-AMRO Margin Agreement

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

As of March 31, 2015 and December 31, 2014, there were no borrowings outstanding under the Margin Agreement and the Company was in compliance with all covenants.

RBC Line of Credit

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

As of March 31, 2015 and December 31, 2014, there were no borrowings outstanding under the RBC Line and the Company was in compliance with all terms and conditions.

Maple Bank Revolver

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

As of March 31, 2015, there was $2,754,814 outstanding under the Maple Agreement and the Company was in compliance with all covenants.

Security State Mortgage

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

As of March 31, 2015 the Company was in compliance with all terms and conditions of the Security State Mortgage.

Lakeview Bank Mortgage

On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon Holdings, LLC (“Kenyon”), a related party, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a note secured by a mortgage on the property and owed to Lakeview Bank (the “Lakeview Bank Mortgage”). Kenyon is owned by Mr. Krieger, the Company’s primary owner and its Chief Executive Officer, and Keith W. Sperbeck, the Company’s Vice President of Operations. The Lakeview Bank Mortgage bears interest at the highest prime rate reported as such from time to time by The Wall Street Journal. Interest only is payable monthly on the 25^th, the note matured on April 30, 2015, and the Company is currently waiting for the bank’s final approval to extend the note to April 30, 2016. The loan may be prepaid in whole or in part at any time without penalty.

As of March 31, 2015, there was $119,976 outstanding under the Lakeview Bank Mortgage and the Company was in compliance with all terms and conditions of the loan.

American Land and Capital Construction Loans

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

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

As of March 31, 2015 and December 31, 2014, there was $662,362 and $184,975, respectively, outstanding under the American Land Construction Loans and the Company was in compliance with all terms and conditions of the agreements.

Renewable Unsecured Subordinated Notes

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

The Company made interest payments during the three months ended March 31, 2015 and year ended December 31, 2014 of $495,455 and $1,304,701, respectively. Total accrued interest on the Subordinated Notes at March 31, 2015 and December 31, 2014 was $1,014,741 and $849,913, respectively.

As of March 31, 2015, the Company had $19,477,701 of its Subordinated Notes outstanding as follows:

Initial Term	Principal Amount		Weighted Average Interest Rate
3 months	$	670,962		11.88%
6 months		390,690		10.55%
1 year		5,741,256		12.44%
2 years		2,930,140		13.31%
3 years		3,743,320		14.62%
4 years		802,385		14.82%
5 years		3,825,905		15.96%
10 years		1,373,043		14.84%
Total	$	19,477,701		13.89%

Weighted average term		36.5 mos

13.

Ownership

As of March 31, 2015 and December 31, 2014, the Company’s ownership is as presented below:

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

As of March 31, 2015 and December 31, 2014 total common and preferred distributions paid to the owners of the respective units were $4,457,000 and $4,727,000 and $91,512 and $549,000, respectively.

14.

Related Party Transactions

On January 1, 2013, the Company and Kenyon Holdings, LLC (“Kenyon”), a company owned by Mr. Krieger and Mr. Sperbeck, entered into a five year lease expiring December 31, 2017 for 11,910 square feet at a monthly rent of $12,264. On September 25, 2014, the lease was amended to reduce the square footage to 10,730 and monthly rent to $11,113. For rent, real estate taxes, and operating expenses, the Company paid Kenyon $58,335 and $61,620 for the three months ended March 31, 2015 and 2014, respectively.

Effective January 1, 2013, in connection with the purchase of David B. Johnson’s units by Mr. Krieger, the Company entered into the NCA with Mr. Johnson, a current governor and former member of the Company, pursuant to which the Company is obligated to pay Mr. Johnson $500,000 in 24 equal monthly installments of $20,833 each. The total amount paid pursuant to the NCA during the three months ended March 31, 2014 was $62,500. There were no payments during the three months ended March 31, 2015 as the NCA was paid in full on December 31, 2014.

On March 5, 2013, CEF entered into a 36 month lease for 1,800 square feet of office space in Tulsa, Oklahoma with the Brandon J. and Heather N. Day Revocable Trust at a monthly rent of $3,750. Mr. Day is an employee of CEF, a second-tier subsidiary of the Company. Total rent paid for the three months ended March 31, 2015 and 2014 was $11,250.

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

On June 17, 2014, the building in which the Company leases its Chandler, Arizona office space occupied by certain of its retail business functions was purchased by Fulton Marketplace, LLC (“Fulton”), a company owned by Mr. Krieger and Mr. Sperbeck. Effective August 1, 2014, the Company and Fulton entered into a five year lease expiring July 31, 2019, subject to two consecutive five year extension periods, for 2,712 square feet. The rent for the first lease year is $4,068 per month and it will increase by 3% annually at the start of each lease year thereafter. The Company paid $16,059 to Fulton for the three months ended March 31, 2015 for rent, real estate taxes, and operating expenses.

Fulton is also the owner of a single family residence located in Chandler, Arizona. Effective December 1, 2014, Fulton and REH entered into a seven month lease expiring June 30, 2015 with respect to the property for rent of $2,800 per month. For the three months ended March 31, 2015 the Company paid Fulton total rent of $8,400.

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

15.

Commitments and Contingencies

FERC Settlement

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

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

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

As of the date hereof, the Company was in compliance with all terms and conditions of the agreement.

Former Employee Litigation

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

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

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

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

Further, on April 24, 2015, the Company commenced a new action against another former employee of TCPC, Guarav Sharma, claiming amounts owing for improperly received bonuses. The action is in its infancy.

In all of this former employee litigation, the parties are proceeding with discovery. A case management justice has been appointed who will assist the parties in scheduling and any required motions.

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

PJM Resettlements

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

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

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

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

PJM Up To Congestion Fees

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

Currently, under PJM’s Tariff and Operating Agreement, UTCs are treated differently under its FTR forfeiture rule than are INCs and DECs, two other types of virtual transactions. Further, INCs and DECs are subject to uplift charges, but UTCs are not. In Docket No EL14-37-000, FERC noted that should any uplift be charged UTCs, it would apply such back to the date that notice of the proceeding was published in the Federal Register (September 8, 2014), thus setting a “refund effective date”. From the refund effective date to March 31, 2015, the Company traded about 4,300,000 MWh of UTCs in PJM and recorded $10,700,000 of associated revenues.

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

Letter of Credit

On June 24, 2014, the Company’s restricted cash balance of $320,188 was returned by the City of Lakeville and a letter of credit in favor of Cyclone was issued by Vermillion State Bank for the same amount. The note evidencing the letter of credit calls for maximum advances of up to $320,188, bears interest at an annual rate of 5.25%, is secured by a mortgage on the property being developed and the guaranty of Cyclone, and matures on demand. As of March 31, 2015 the Company was in compliance with all terms and conditions of the letter of credit.

Guarantees

In the ordinary course, the Company provides guarantees of the obligations of TCP, SUM, and CEF with respect to their participation in certain ISOs. As of March 31, 2015, such guarantees were in an unlimited amount for PJM, an unlimited amount for NYISO, up to $2,000,000 for MISO, and up to $5,000,000 for ERCOT.

On August 12, 2013, the Company entered into a guaranty of the obligations of TSE of up to $1,000,000 (plus any costs of collection or enforcement) in favor of Noble Americas Energy Solutions LLC (“Noble”). The Company may cancel the guarantee upon 30 days’ written notice to Noble.

On April 25, 2014, the Company entered into a guaranty of the obligations of DEG of up to $1,000,000 (plus any costs of collection or enforcement) in favor of Noble. The Company may cancel the guarantee upon 30 days’ written notice to Noble.

On November 5, 2014, the Company entered into two separate guaranties of the obligations of TSE and DEG of up to $500,000 (plus any costs of enforcement or collection) in favor of Shell Energy North America L.P. (“Shell”). The guarantee is in effect until the earlier of November 5, 2019 or ten days’ after the Company gives notice to Shell of its cancellation.

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

16.

Segment Information

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

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

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

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

Trading profits and sales are classified as “foreign” or “domestic” based on the location where the trade or sale originated. For the three months ended March 31, 2015 and the year ended December 31, 2014, all such transactions were “domestic”. Furthermore, the Company has no long-lived assets in foreign jurisdictions.

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

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

Information on segments for the three months ended and at March 31, 2015 is as follows:

	Wholesale Trading		Retail Energy Services			Diversified Investments			Corporate, Net of Eliminations			Consolidated Total
Three Months Ended March 31, 2015
Wholesale trading	$	10,765,796	$	83,900		$	–		$	–		$	10,849,696
Retail energy services		–		5,377,109			–			–			5,377,109
Revenues, net		10,765,796		5,461,009			–			–			16,226,805

Costs of retail electricity sold		–		6,223,221			–			–			6,223,221
Retail sales and marketing		–		245,899			–			–			245,899
Compensation and benefits		5,392,261		188,315			–			615,663			6,196,239
Professional fees		28,950		255,451			1,200			300,779			586,380
Other general and administrative		1,498,589		617,668			41,274			(921,466	)		1,236,065
Trading tools and subscriptions		235,851		83,467			198			7,789			327,305
Operating costs and expenses		7,155,651		7,614,021			42,672			2,765			14,815,109
Operating income (loss)	$	3,610,145	$	(2,153,012	)	$	(42,672	)	$	(2,765	)	$	1,411,696

Capital expenditures	$	–	$	15,827		$	211,295		$	109,032		$	336,154

At March 31, 2015
Identifiable Assets
Cash - unrestricted	$	2,117,589	$	667,990		$	864		$	1,609,562		$	4,396,005
Cash in trading accounts		14,405,146		1,598,815			–			–			16,003,961
Accounts receivable - trade		1,507,259		4,042,082			–			22,464			5,571,805
Marketable securities		–		–			–			2,579,875			2,579,875
Prepaid expenses and other assets		75,898		42,974			30,943			134,729			284,544
Total current assets		18,105,892		6,351,861			31,807			4,346,630			28,836,190

Property, equipment and furniture, net		51,909		106,345			1,000			686,969			846,223
Intangible assets, net		–		192,103			–			–			192,103
Deferred financing costs, net		–		26,979			–			218,645			245,624
Cash - restricted		–		–			–			1,319,371			1,319,371
Land held for development		–		–			1,642,143			–			1,642,143
Investment in convertible notes		–		–			1,642,380			–			1,642,380
Total assets	$	18,157,801	$	6,677,288		$	3,317,330		$	6,571,615		$	34,724,034

Identifiable Liabilities and Equity
Accounts payable - trade	$	155,554	$	1,941,229		$	7,733		$	601,562		$	2,706,078
Accrued expenses		4		942,520			–			3,571			946,095
Accrued compensation		4,505,677		–			–			–			4,505,677
Accrued distributions		–		–			–			45,756			45,756
Accrued interest		–		16,716			–			1,014,741			1,031,457
Revolver		–		2,754,814			–			–			2,754,814
Senior notes		–		–			782,338			7,203			789,541
Subordinated notes		–		–			–			8,102,083			8,102,083
Obligations under settlement agreement		–		–			–			582,565			582,565
Total current liabilities		4,661,235		5,655,279			790,071			10,357,481			21,464,066

Senior notes		–		–			–			215,617			215,617
Subordinated notes		–		–			–			11,375,618			11,375,618
Obligations under settlement
agreement		–		–			–			2,330,260			2,330,260
Total liabilities		4,661,235		5,655,279			790,071			24,278,976			35,385,561

Investment in subsidiaries		12,512,830		1,444,433			2,527,259			(16,484,522	)		–
Series A preferred equity		–		–			–			2,745,000			2,745,000
Common equity		–		–			–			(3,955,265	)		(3,955,265	)
Accumulated other comprehensive income		983,736		(422,424	)		–			(12,574	)		548,738
Total members' equity		13,496,566		1,022,009			2,527,259			(17,707,361	)		(661,527	)
Total liabilities and equity	$	18,157,801	$	6,677,288		$	3,317,330		$	6,571,615		$	34,724,034

Information on segments for the three months ended March 31, 2014 is as follows:

	Wholesale Trading		Retail Energy Services			Diversified Investments			Corporate, Net of Eliminations			Consolidated Total
Three Months Ended March 31, 2014
Wholesale trading	$	25,209,520	$	1,812,205		$	–		$	–		$	27,021,725
Retail energy services		–		2,912,526			–			–			2,912,526
Revenues, net		25,209,520		4,724,731			–			–			29,934,251

Costs of retail electricity sold		–		4,602,217			–			–			4,602,217
Retail sales and marketing		–		128,442			–			–			128,442
Compensation and benefits		10,616,037		75,282			–			349,380			11,040,699
Professional fees		112,733		280,431			–			334,158			727,322
Other general and administrative		1,159,049		563,268			24,228			(842,218	)		904,327
Trading tools and subscriptions		190,861		16,635			775			10,935			219,206
Operating costs and expenses		12,078,680		5,666,275			25,003			(147,745	)		17,622,213
Operating income (loss)	$	13,130,840	$	(941,544	)	$	(25,003	)	$	147,745		$	12,312,038

Capital expenditures	$	2,687	$	683,094		$	22,279		$	19,399		$	727,459

At March 31, 2014
Identifiable Assets
Cash - unrestricted	$	8,714,683	$	1,119,874		$	–		$	1,448,662		$	11,283,219
Cash in trading accounts		16,155,968		2,876,734			–			–			19,032,702
Accounts receivable - trade		2,051,474		767,134			–			1,342			2,819,950
Marketable securities		–		–			–			1,018,594			1,018,594
Prepaid expenses and other assets		117,073		35,423			–			119,573			272,069
Total current assets		27,039,198		4,799,165			–			2,588,171			34,426,534

Equipment and furniture, net		64,780		63,178			–			356,054			484,012
Intangible assets, net		–		523,800			–			187,500			711,300
Deferred financing costs, net		–		–			–			312,061			312,061
Cash - restricted		–		–			320,188			1,319,371			1,639,559
Land held for development		–		–			132,756			–			132,756
Mortgage receivable		–		–			353,504			–			353,504
Convertible promissory note		–		–			1,003,056			–			1,003,056
Total assets	$	27,103,978	$	5,386,143		$	1,809,504		$	4,763,157		$	39,062,782

Identifiable Liabilities and Equity
Accounts payable - trade	$	311,722	$	326,934		$	10,169		$	381,899		$	1,030,724
Accrued expenses		–		901,668			–			2,699			904,367
Accrued compensation		9,647,059		–			–			15,000			9,662,059
Accrued interest		–		–			–			525,027			525,027
Subordinated notes		–		–			–			6,026,480			6,026,480
Obligations under non-competition agreement		–		–			–			187,500			187,500
Total current liabilities		9,958,781		1,228,602			10,169			7,138,605			18,336,157

Subordinated notes		–		–			–			5,761,241			5,761,241
Total liabilities		9,958,781		1,228,602			10,169			12,899,846			24,097,398

Investment in subsidiaries		16,846,406		3,839,062			1,799,335			(22,484,803	)		–
Series A preferred equity		–		–			–			2,745,000			2,745,000
Common equity		–		–			–			11,621,437			11,621,437
Accumulated other comprehensive income		298,791		318,479			–			(18,323	)		598,947
Total members' equity		17,145,197		4,157,541			1,799,335			(8,136,689	)		14,965,384
Total liabilities and equity	$	27,103,978	$	5,386,143		$	1,809,504		$	4,763,157		$	39,062,782

17.

Subsequent Events

From April 1 to May 12, 2015, the Company sold additional Subordinated Notes totaling $2,057,622 with a weighted average term of 29.2 months and bearing a weighted average interest rate of 14.44%.

On January 26, 2015, Cyclone closed on the purchase of a single family home for a price of $195,035. On April 13, 2015, Tim Krieger personally bought the property from Cyclone for a price of $197,382.

Effective April 2, 2015, Discount Energy Group, LLC changed its name to Town Square Energy East, LLC.

On April 13, 2015, the Company pledged additional collateral of $700,000 to PJM and consequently cancelled its guarantees for the benefit of PJM with respect to TCP and SUM effective April 30, 2015.

Effective April 30, 2015, CTG became a first tier subsidiary of TCPH.

On May 8, 2015 the Company filed a replacement registration statement on Form S-1 relating to the offer and sale of our Renewable Unsecured Subordinated Notes (the “2015 S-1”). The 2015 S-1 covers up to $75,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes.

On May 13, 2015, the Company gave notice to ERCOT and NYISO of the cancellation of its guarantees of TCP’s obligations, and the concurrent pledge of $500,000 of additional collateral to each.

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

Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our consolidated financial statements, notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from our 2014 Form 10-K, and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-Q under the heading “Forward-Looking Statements” located on page 8, “Item 1A – Risk Factors” of our 2014 Form 10-K, and the “Risk Factors” section beginning on page 10 of our Form S-1.

The risks and uncertainties described in this Form 10-Q, our 2014 Form 10-K, and our Form S-1 are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition, or results of operations could suffer if the risks set forth are realized.

Industry Background

Electric power in commercial quantities, unlike other energy commodities such as coal or natural gas, cannot be stored - the supply must be produced or generated exactly when used or demanded by customers. Further, the laws of physics dictate that power flows within a network along the lines of least resistance, not necessarily where we may want it to go. These facts, coupled with the necessity of electricity in modern life, have obvious implications for market structures and regulations.

Overall, according to EIA data for 2013 (the most recent year for which full data is available), the U.S. electric power industry generated and sold 3,725 TWh at retail (up 0.8% from 2012) for a little more than $375.7 billion (up 3.3%) to over 146.4 million residential, commercial, industrial, and transportation customers (up 0.5%). In 2013, the average U.S. retail electricity price was 10.09¢/kWh - residential customers paid 12.13¢/kWh, commercial users paid 10.31¢/kWh, and industrial and transportation consumers paid 6.90¢/kWh.

Today, the industry includes any entity producing, selling, or distributing electricity. As of the end of 2013, according to the EIA, participants numbered about 2,800 and included investor-owned, publicly-owned, cooperative, and federal utilities and non-utility power producers. Power marketers and retail energy providers do not own any generation but buy and sell in wholesale and retail markets. Finally, participants in wholesale power markets include banks, hedge funds, private equity firms, and trading houses.

The investor-owned portion of the industry, including utilities, retail energy providers, and non-utility generators, constitutes over 70% of the industry’s revenues, unit sales, and customers. According to the Edison Electric Institute, a trade group representing the largest investor-owned utilities, in 2013, total energy operating revenues of shareholder-owned electric companies were $356.5 billion. As of December 31, 2013, consolidated holding company-level assets of these entities were $1.292 trillion, and of these assets, $791.8 billion were net property in service. As of the same date, the total market capitalization of U.S. shareholder-owned electric companies was $504.4 billion.

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

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

Electricity Prices

Today, wholesale prices are subject to a federal regulatory framework focused on ensuring fair competition and reliability of supply. At the state level, under the traditional system which most states continue to employ, a vertically integrated utility is responsible for serving all consumers in a defined territory and customers are obligated to pay the regulated rate for their class of service. However, in a state with a restructured or “deregulated” market, i.e., one with retail choice, the generation, transmission, distribution, and retail marketing functions of the business are legally separated and consumer pricing is unbundled.

Wholesale electricity prices are driven by supply and demand and actually change minute-by-minute. Near term demand is largely affected by the weather and consumer behavior while supply is driven by plant availability and fuel prices, particularly for natural gas as it is the fuel of choice for marginal generation requirements. In the longer term, retail electricity prices reflect supply-side factors such as fuel prices and availability, generation technologies, plant and line construction and maintenance costs, and capital costs. Demand-side factors include population growth, economic activity, and energy efficiency. Governmental policies and regulations with respect to energy and the environment affect both the supply of, and demand for, electricity.

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

Wholesale Electricity Markets

After PURPA, the Energy Policy Act of 1992 was the next major legislative step towards full deregulation of wholesale power markets. In 1996, FERC issued Orders 888 and 889, which allowed for energy to be scheduled across multiple power systems, and in 1999, FERC issued Order 2000 calling for electric utilities to form RTOs or ISOs to operate the nation’s bulk power system. The intended benefits of ISOs include eliminating discriminatory access to transmission for all generators, improving operating efficiency, and increasing system reliability. ISOs are typically not-for-profit entities using governance models developed by FERC. To date, seven ISOs have been formed in the U.S. In the parts of the country where ISOs have not been established, including the southeast, southwest and northwest, active wholesale markets are still present, although they operate with different structures.

In addition to controlling the physical flow of power within its area of responsibility via direction to generators operating within the ISO’s footprint, many ISOs also operate wholesale markets for real-time and day-ahead energy, as well as for generating capacity and ancillary services required to ensure system reliability.

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

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

Retail Electricity Markets

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

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

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

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

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

Type 1		All residential, commercial, and industrial customers may choose their energy provider. While this applies primarily in areas served by investor-owned utilities, in certain jurisdictions, customers of specific cooperatives and public utilities may also have choice but these instances are rare;

Type 2		A limited number of residential customers have choice and the choice of non-residential customers is capped, usually at a specific number of megawatt-hours per year;

Type 3		No residential customers have choice and the choice of non-residential customers is capped; and

Type 4		No residential customers have choice and the number of non-residential with choice is limited.

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

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

In the 14 areas where all rate classes had choice during 2013, according to EIA data, 25.58 million residential and 3.14 million non-residential customers were eligible to choose their supplier. Of these totals, 11.15 million residential (43.6%) and 1.91 million non-residential (61.2%) customers purchased over 559 million MWh from competitive suppliers.

Unbundling of consumer electric bills in restructured markets made many aware for the first time exactly what they were paying for. In general, the bills of retail electricity customers include numerous costs and charges that can be classified into three major categories – generation costs, delivery charges, and governmental policy costs, such as societal benefits charges such as universal service, lifeline service, and energy efficiency programs, and sales and use taxes.

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

Company Overview

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

Through our wholly-owned subsidiaries, we trade financial and physical electricity contracts in North American wholesale markets regulated by FERC and operated by ISOs and RTOs, trade energy derivative contracts on exchanges regulated by the CFTC, including ICE, NGX, and CME, provide electricity supply services to retail customers in certain states that permit retail choice, and are engaged in certain investment and real estate development activities. Consequently, we have three major business segments used to measure our activity – wholesale trading, retail energy services, and diversified investments.

Our organizational structure (active entities only) as of May 13, 2015 is outlined below.

Key

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

Wholesale Trading

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

For the three months ended March 31, 2015 and 2014, financial and virtual electricity represented 100% of our total trading volume in FERC-regulated markets, that is, we traded no physical power during these periods in our wholesale segment.

Retail Energy Services

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

As of March 31, 2015, we were actively marketing our services in 16 of these service areas. Projected margins in specific areas ultimately determine where we deploy our retail marketing resources and obtain customers. To date, our customer base consists largely of residential consumers with a few small commercial accounts. We primarily use direct marketing strategies to sell our services and our customers may typically cancel their contracts at any time.

Diversified Investments

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

Derivative Instruments

In our wholesale operations, we use derivative contracts for trading purposes, seeking to profit from perceived opportunities driven by expected changes in market prices. These contracts include exchange-traded instruments such as futures contracts, which are Level 1 instruments in the fair value hierarchy as well as FTRs available through certain FERC-regulated markets, which we consider to be Level 3 instruments as they are not regularly quoted.

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

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

The table below details our open derivative contracts held for trading purposes, as undesignated, economic hedges by our retail segment, and as cash flow hedges by our retail segment as of March 31, 2015:

Open Derivative Contracts Held for Trading

As of March 31, 2015

Delivery

Final

Energy

Fair Value

Segment and contract type

Hub or zone

period

settlement

(MWh)

Asset

Liability

Wholesale Trading

FTRs

MISO, NYSIO, PJM, ISO NE

Q2 2015

various

3,579,010

539,838

–

Natural gas future

Henry Hub

Q2 2015

various

310,000

–

775

Electricity future

AESO

Q2 2015

various

183,080

1,180,979

1,244,954

Electricity future

AESO

Q3 2015

various

29,760

240,463

245,123

Electricity future

AESO

Q4 2015

various

66,240

375,427

330,615

Electricity future

AESO

Q1 2016

various

10,920

67,263

61,842

Electricity future

AESO

Q2 2016

various

10,920

–

62,715

Electricity future

AESO

Q3 2016

various

11,040

94,739

53,328

Electricity future

AESO

Q4 2016

various

11,040

67,156

53,328

Subtotal

4,212,010

2,565,865

2,052,680

Retail Energy Services - Economic Hedges

Electricity futures

PJM West Hub

Q2 2015

various

1,840

–

24,780

Electricity futures

PJM West Hub

Q3 2015

various

17,623

36,616

76,417

Electricity futures

PJM West Hub

Q4 2015

various

16,165

–

108,300

Subtotal

35,628

36,616

209,497

Retail Energy Services - Designated Cash Flow Heges

Electricity futures

ISO-NE Mass Hub

Q2 2015

various

16,120

–

238,511

Electricity futures

ISO-NE Mass Hub

Q3 2015

various

29,440

51,728

229,850

Electricity futures

ISO-NE Mass Hub

Q4 2015

various

352

–

5,791

Subtotal

45,912

51,728

474,152

Totals

4,293,550

2,654,209

2,736,329

Open Derivative Contracts

As of December 31, 2014

Delivery

Final

Energy

Fair Value

Segment and contract type

Hub or zone

period

settlement

(MWh)

Asset

Liability

Wholesale Trading

Electricity futures

PJM West Hub peak

daily

6,400

22,400

–

FTRs

MISO, NYISO, PJM

Q1 & Q2 2015

various

8,981,440

1,435,819

–

Electricity futures

AESO

Q1 2015

various

80,320

785,617

286,250

Electricity futures

AESO

Q2 2015

various

135,600

892,838

1,094,059

Electricity futures

AESO

Q3 2015

various

78,120

601,993

783,893

Subtotal

9,281,880

3,738,667

2,164,202

Retail Energy Services - Economic Hedges

Electricity futures

ISO-NE Mass Hub; PJM West Hub

Q1 2015

various

3,715

–

44,373

Electricity futures

PJM West Hub

Q2 2015

various

14,280

–

107,120

Natural gas futures

Henry Hub

Q2 2015

various

155,000

14,803

–

Electricity futures

PJM West Hub

Q3 2015

various

16,240

31,926

65,196

Natural gas futures

Henry Hub

Q3 2015

various

77,500

1,085

–

Electricity futures

PJM West Hub

Q4 2015

various

21,285

–

175,971

Subtotal

288,020

47,814

392,660

Retail Energy Services - Designated Cash Flow Hedges

Electricity futures

ISO-NE Mass Hub

Q1 2015

various

13,995

–

498,166

Electricity futures

ISO-NE Mass Hub

Q2 2015

various

16,120

–

184,378

Electricity futures

ISO-NE Mass Hub

Q3 2015

various

18,480

15,732

189,116

Electricity futures

ISO-NE Mass Hub

Q4 2015

various

352

–

7,480

Subtotal

48,947

15,732

879,140

Total

9,618,847

3,802,213

3,436,002

Results of Operations

Three Months Ended March 31, 2015 and 2014

The following table sets forth selected financial data for the periods indicated, which has been derived from the consolidated financial statements included in this report:

	For The Three Months Ended March 31,
Dollars in thousands	2015					2014					Increase (decrease)
	Dollars			Percent		Dollars			Percent		Dollars			Percent
Revenue
Wholesale trading revenue, net	$	10,850			66.9%	$	27,021			90.3%	$	(16,171	)		-59.8%
Retail electricity revenue		5,377			33.1%		2,913			9.7%		2,464			84.6%
Net revenue		16,227			100.0%		29,934			100.0%		(13,707	)		-45.8%

Operating costs & expenses
Cost of retail electricity sold		6,223			38.3%		4,602			15.4%		1,621			35.2%
Retail sales and marketing		246			1.5%		129			0.4%		117			90.7%
Compensation and benefits		6,196			38.2%		11,041			36.9%		(4,845	)		-43.9%
Professional fees		586			3.6%		727			2.4%		(141	)		-19.4%
Other general & administrative		1,236			7.6%		904			3.0%		332			36.7%
Trading tools & subscriptions		327			1.9%		219			0.6%		108			49.3%
Total operating expenses		14,814			91.3%		17,622			58.9%		(2,808	)		-15.9%
Operating income		1,413			8.7%		12,312			41.1%		(10,899	)		-88.5%

Interest expense		(764	)		-4.7%		(467	)		-1.6%		(297	)		63.6%
Interest income		49			0.3%		12			-0.1%		37			308.3%
Loss on foreign currency exchange		95			0.6%		–			0.0%		95			na
Other income		40			0.2%		–			0.0%		40			na
Other expense, net		(580	)		-3.7%		(455	)		-1.5%		(125	)		27.5%
Net income		833			5.1%		11,857			39.6%		(11,024	)		-93.0%

Preferred distributions		(137	)		-0.8%		(137	)		-0.5%		–			0.0%
Net income attributable to common	$	696			4.3%	$	11,720			39.2%	$	(11,024	)		-94.1%

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

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

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

Market conditions during the first quarter of 2015 were characterized by slightly cooler than normal weather, with 199 more heating degree-days than normal and an average temperature only 0.5° below the normal (37.1°F versus 37.6°F), and cheaper than normal natural gas (down about 8% to $2.90/MCF versus the 5 year average of $3.96/MCF).

The first quarter of 2015 was warmer than the same period in 2014. Heating degree-days for the U.S. in the first quarter of 2015 totaled 2,370 or 5% below 2014’s figure of 2,492 and cooling degree-days totaled 43 compared to 31 in 2014. For 2015, the Henry Hub natural gas spot price averaged $2.90/MCF, 43% below 2014’s $5.08 mark. Supplies of gas during 2015 were adequate. Weekly storage levels averaged 2,119 BCF or 30% more than 2014’s level of 1,633 and 8% lower than the 5 year average of 2,291.

	Three Months Ended March 31,
							Increase (decrease)
	Units						This year vs last year					This year vs LTA
	2015		2014		LTA (1)		Units			Percent		Units			Percent
U.S. Weather
Heating degree-days		2,370		2,492		2,171		(122	)		-5%		199			9%
Cooling degree-days		43		31		36		12			39%		7			21%
Avg temperature (°F)		37.1°F		34.3°F		37.6°F		2.8°F			8%		-0.4°F			-1%

Natural Gas
Henry Hub spot price ($/MCF)		2.90		5.08		3.96		(2.18	)		-43%		(1.06	)		-27%
Working gas in underground storage, Lower 48 states,
EIA weekly estimates (BCF)		2,119		1,633		2,291		486			30%		(173	)		-8%

_______________

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

The average for the day-ahead PJM West Peak price during 2015 was $53.72/MWh with a standard deviation of $36.08 resulting in a coefficient of variation of 67%, compared to $102.50/MWh, $97.51, and 95% for 2014. The high for the year to date was $237.48/MWh and the low was $28.49. As shown by the table below, price levels and volatility were generally lower in 2015 as compared to 2014.

	Three Months Ended March 31,
PJM West Hub Peak Day Ahead					Increase (decrease)
	2015		2014		Units			Percent
*Price ($/MWh)*
Average		53.72		102.50		(48.78	)		-48%
Maximum		237.48		655.75		(418.27	)		-64%
Minimum		28.49		37.15		(8.66	)		-23%
Standard deviation		36.08		97.51		(61.43	)		-63%
Coefficient of variation (stdev ÷ avg)		67%		95%		-28%			-29%

*Daily percentage changes*
Average		4.1%		8.7%		-4.6%			-53%
Maximum		209.3%		200.3%		9.0%			4%
Minimum		-63.5%		-78.1%		14.7%			-19%
Standard deviation		33.8%		47.4%		-13.5%			-29%

*Number of days*
Up 10% or more		20		22		(2	)		-9%
Between 10% up and 10% down		23		17		6			35%
Down 10% or more		20		24		(4	)		-17%

Largely as a result of these factors, for the three months ended March 31, 2015, net trading revenue decreased by $16,171,000 or 59.8% compared to $27,021,000 for the same period in 2014.

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.

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

For the three months ended March 31, 2015 and 2014, we recorded total revenues in our retail segment of $5,461,000 and $4,725,000, respectively. These totals consisted of retail energy sales of $5,377,000 in 2015 and $2,913,000 in 2014, up 84.6%, and wholesale trading revenues of $84,000 and $1,812,000, down 95.4%. 2015’s results were driven by a 302.1% increase in customers as a result of increased marketing efforts.

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

Key Operating Statistics	For and at three months ended March 31,
(in units unless otherwise indicated)					Increase (decrease)
	2015		2014		Units			Percent
Retail electricity sales ($000s)		5,377		2,913		2,464			84.6%
Wholesale trading revenue, net ($000s)		84		1,812		(1,728	)		-95.4%
Total segment revenues ($000s)		5,461		4,725		736			15.6%

Unit sales (MWh)		56,469		27,352		29,117			106.5%
Weighted average retail price (¢/kWh)		9.52		10.65		(1.13	)		-10.6%

Customers receiving service, end of period		29,608		7,364		22,244			302.1%

During 2015, retail energy sales revenue increased principally as a result of an increase in customer count. Our customer base is a combination of residential and commercial accounts.

We primarily use direct marketing strategies to acquire our customers.

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

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

During the quarters ended March 31, 2015 and 2014, the Company recorded no revenue but capitalized a total of $688,000 and $133,000, respectively, of costs associated with its real estate development activities, consisting primarily of purchases of land for development and construction costs incurred.

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

Costs of retail electricity sold: Our costs of electricity sold include the cost of purchased power, EDC service fees, renewable energy certificates, bad debt expense, and gains net of losses and commissions on derivative contracts used to hedge power purchase costs. Cost of sales does not include the net gain or loss on the economic hedges described above. During the first quarters of 2015 and 2014, we purchased electricity for sale to retail customers in ISO-NE’s and PJM’s wholesale markets and from certain other wholesale suppliers. We are typically required to maintain cash deposits in separate accounts to meet our wholesale energy vendors’ financial assurance requirements to purchase energy, ancillary services, and capacity which amount is included in “cash in trading accounts”.

During the first three months of 2015, we hedged the cost of 14,795 MWh or 26% of the 56,469 MWh of electricity sold to our retail customers. Year to date, our hedges had the effect of increasing the cost of retail electricity sold by $475,608.

During the first quarter of 2014, we hedged the cost of 15,835 MWh or 58% of the 27,373 MWh of electricity sold to our retail customers. For the year, our hedges had the effect of decreasing the cost of retail electricity sold by $571,505.

As shown by the Open Derivative Contracts table on page 44, as of March 31, 2015, we had designated 45,912 MWh of electricity futures as hedges against the cost of expected 2015 electricity purchases and $422,000, representing the net loss on the effective portion of the hedges, was deferred in accumulated other comprehensive income and this entire amount is expected to be reclassified to cost of retail electricity sold by December 31, 2015.

As of December 31, 2014 as shown by the Open Derivative Contracts table on page 45, we had designated 48,947 MWh of electricity futures as hedges against the cost of expected 2015 electricity purchases. $863,000, representing the net loss on the effective portion of the hedges, was deferred in AOCI and this entire amount is expected to be reclassified to cost of retail electricity sold by December 31, 2015.

In total, during the first quarters of 2015 and 2014, we recorded costs of retail electricity sold of $6,223,000 and $4,602,000, respectively, resulting in gross loss of $762,000 in 2015 and a profit of $122,000 in 2014. If the economic hedges were treated in the same way as that of the designated hedges, that is, with gains decreasing costs of sales and with losses increasing such, gross margins would have been -14% in 2015 and 4% for 2014.

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

During the first quarters of 2015 and 2014, we spent $246,000 and $129,000 on retail sales and marketing, principally on outbound telemarketing.

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

For the first quarter of 2015, salaries, wages, and related costs decreased by $4,845,000 or 43.9% to $6,196,000 compared to $11,041,000 for the same period in 2014. Our personnel expense is directly related to the revenue we record, since our trader’s compensation is tied to revenue production, this decrease in expense is in line with the decrease in revenues.

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

For the first three months of 2015, professional fees decreased by $141,000 to $586,000 compared to $727,000 in the first quarter of 2014. The majority of the decrease is due to professional fees incurred during the first three months of 2014 for recruiter fees to hire additional traders.

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

For the first quarter of 2015, these costs increased by approximately $332,000 to $1,236,000 compared to $904,000 for 2014. The increase was primarily related to additional spending on marketing and administrative expenses associated with the Notes Offering. We incurred $533,000 and $234,000 in marketing and administrative expenses associated in the first quarters of 2015 and 2014, respectively.

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 three months ended March 31, 2015, trading tools and subscriptions expense increased by $108,000 or 49.3% to $327,000 compared to $219,000 for the same period in 2014, primarily due to an increase in subscription costs due to the increase in the number of traders and the increase cost per subscription during the first three months of March 31, 2015. In addition, our increased customer count increased our volumetric fees that we incur for services that we utilize for billing our retail customers.

Other income (expense): Other expense, net of other income, increased by $125,000 to $580,000 for the first quarter of 2015 compared to $455,000 for the same period in 2014. As the principal component of other expense, interest expense increased by $297,000 to $764,000 for 2015 year to date compared to $467,000 for the same period in 2014. The increase was attributed primarily to an increase in outstanding debt of $3,950,000 for the three month period ended March 31, 2015 compared to $1,603,000 for the three month period ended March 31, 2014.

Preferred distributions: During the first quarters of 2015 and 2014, we distributed $137,000 to our preferred unit holder.

Liquidity, Capital Resources, and Cash Flow

In our wholesale trading business, we require a significant amount of cash to pledge as collateral to market operators which allows us to trade and generate revenues. With respect to our retail operation, in addition to collateral posted with ISOs that allows us to acquire power for our customers, we are also required to fund accounts receivable as well as margin requirements associated with hedges. We are generally required to pay for power every 4 days or so, while our average collection period on receivables is 40 to 45 days. As such, our capital is largely invested in trading accounts and deposits and receivables. Our capital expenditure requirements are nominal, being limited largely to computer and office equipment, software, and office furniture. Therefore, in any given reporting period, the amount of cash consumed or generated will primarily be due to changes in working capital.

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

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

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

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

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

	At
Dollars in thousands	March 31, 2015					December 31, 2014					Increase (decrease)
	Dollars			Percent of total assets		Dollars			Percent of total assets		Dollars			Percent
Liquidity
Cash - unrestricted	$	4,396			12.7%	$	2,397			7.5%	$	1,999			83.4%
Cash in trading accounts		16,004			46.1%		21,100			66.4%		(5,096	)		-24.2%
Accounts receivable - trade		5,572			16.0%		2,394			7.5%		3,178			132.7%
Total liquid assets*		25,972			74.8%		25,891			81.6%		81			0.3%
Total assets	$	34,724			100.0%	$	31,770			100.0%		2,954			9.3%

Capital Resources
Current	$	11,646			33.5%	$	8,652			27.2%	$	2,994			34.6%
Long term		11,591			33.4%		10,636			33.5%		955			9.0%
Total debt		23,237			66.9%		19,288			60.7%		3,949			20.5%

Series A preferred		2,745			7.9%		2,745			8.6%		–			0.0%
Common		(3,955	)		-11.4%		(194	)		-0.6%		(3,761	)		1938.7%
Accumulated other comprehensive income		549			1.6%		147			0.5%		402			273.5%
Total equity		(661	)		-1.9%		2,698			8.5%		(3,359	)		-124.5%
Total capitalization	$	22,576			64.9%	$	21,986			69.1%	$	590			2.7%

____________________

* - Closest GAAP measure is total current assets, which was $28,836,000 as of March 31, 2015 and $26,619,000 as of December 31, 2014

The table below summarizes our primary sources and uses of cash for the three month periods ended March 31, 2015 and 2014 as derived from the statements of cash flows included in this Form 10-K.

	For the Three Months Ended March 31,
Dollars in thousands							Increase (decrease)
	2015			2014			Dollars			Percent
Net cash provided by (used in):
Operating activities	$	5,781		$	11,825		$	(6,044	)		-51.1%
Investing activities		(2,630	)		(3,660	)		1,030			-28.1%
Financing activities		(1,127	)		2			(1,129	)		-56450.0%
Net cash flow		2,024			8,167			(6,143	)		-75.2%

Effect of exchange rate changes on cash		(26	)		(75	)		49			-65.3%

Cash - unrestricted:
Beginning of period		2,397			3,190			(793	)		-24.9%
End of period	$	4,395		$	11,281		$	(6,887	)		-61.0%

For the quarter ended March 31, 2015, we generated $5,781,000 from operating activities. The largest sources of cash from operations was a decrease from our trading accounts and deposits of $5,511,000. The most significant items affecting our operating cash flow was a $1,162,000 increase in accounts payable for the cost of retail electricity sold, which was directly related to the growth in the customer count during the three months ended March 31, 2015. Due to the trading revenue earned during the three months ended March 31, 2015 there was also an increase in accrued compensation of $904,000. Growth in accounts receivable also used $3,178,000 of cash.

During the period, we used $2,630,000 of cash for investing activities, primarily related to the purchase of additional marketable securities of $2,250,000 during the three months ended March 31, 2015.

At March 31, 2015, our debt totaled $23,238,000 compared to $11,788,000 as of the prior three month period ended March 31, 2014. For the period, we used $1,127,000 for financing activities, including a net $3,472,000 increase in debt and payment of $4,549,000 in distributions. Of the total distribution amount, $92,000 was paid to the holder of our preferred units and $4,457,000 was paid to our common unit-holders.

For the three months ended March 31, 2014, we generated $11,825,000 from operating activities. The largest sources of cash from operations were net income of $11,857,000. During 2014, we used $3,660,000 of cash for investing activities, with the largest expenditures being for $1,319,000 to secure our position with the Canadian court in conjunction with the former employee litigation (see “Note 15 Commitments and Contingencies – Former Employee Litigation”), the purchase of marketable securities of $750,000, our investment in Ultra Green’s convertible notes consumed $1,000,000, and finally the acquisition of DEG for 680,000. At March 31, 2014, our debt totaled $11,788,000 compared to $10,185,000 as of the prior year end. For the quarter, the Company received $2,000 for financing activities, including a net increase in debt of $1,603,000 and payment of $1,538,000 in distributions. Of the total distribution amount, $137,000 was paid to the holder of our preferred units and $1,401,000 was paid to our common unit-holders.

Financing

In February 2012, we executed a $25,000,000 Futures Risk-Based Margin Finance Agreement (the “Margin Line” and the “Margin Agreement”, respectively) with ABN AMRO. The Margin Agreement provides CEF with an uncommitted $25,000,000 revolving line of credit for which it pays a commitment fee of $35,000 per month. Loans under the Margin Agreement are secured by all balances in CEF’s trading accounts with ABN AMRO, are payable on demand, and bear interest at an annual rate equal to 1.00% in excess of the Federal Funds Target Rate, or approximately 1.25%. Under the Margin Agreement, the Company is also subject to certain reporting, affirmative, and negative covenants, including maintenance of minimum account net liquidating equity as defined of $3,000,000, a maximum loan ratio as defined of 12.5:1, and minimum consolidated tangible net worth of 4% of the amount of the Margin Line or $1,000,000. The Margin Agreement was amended on May 31, 2013 to reduce the uncommitted credit line to $15,000,000, the commitment fee to $25,000 per month, and the covenant with respect to net liquidating equity as defined to $1,500,000. There were no borrowings outstanding under the Margin Line as of March 31, 2015.

On May 10, 2012, our Form S-1 registration statement relating to the offer and sale of our Renewable Unsecured Subordinated Notes (File No. 333-179460) was declared effective by the SEC, and the offering of notes commenced on May 15, 2012. The registration statement on Form S-1 covers up to $50,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes.

For the first three months ended March 31, 2015 and 2014, we incurred $597,000 and $245,824, respectively, of offering-related expenses, including marketing and printing expense, legal and accounting fees, filing fees, and trustee fees. These costs and expenses are expensed as incurred. From the effective date of May 10, 2012 through May 12, 2015, we have sold a total of $24,642,000 in principal amount of Notes and repaid $3,213,000, for a net raise to date of $21,429,000.

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

On October 14, 2014, REH, TSE, and DEG entered into a Credit Agreement with the Toronto, Ontario branch of Maple Bank GmbH (the “Maple Agreement” and “Maple Bank”), expiring October 31, 2016. The Maple Agreement provides the Company’s retail energy services businesses with a revolving line of credit of up to $5,000,000 in committed amount secured by a first position security interest in all of the assets of REH and its subsidiaries, a pledge of the equity of such businesses by TCPH, and certain validity and financial guarantees. Availability of loans is keyed to advance rates against eligible receivables as defined. Any loans outstanding bear interest at an annual rate equal to 3 month LIBOR, subject to a floor of 0.50%, plus a margin of 6.00%. In addition, the Company is obligated to pay an annual fee of 1.00% of the committed amount on a monthly basis and a monthly non-use fee of 1.00% of the difference between the committed amount and the average daily principal balance of any outstanding loans. The Company is also subject to certain customary reporting, affirmative, and negative covenants. As of March 31, 2015, $2,755,000, respectively, was outstanding under the Maple Agreement.

On November 21, 2014, American Land and Capital, LLC (“American Land”) and Cyclone entered into four construction loan agreements, each for a committed amount of $205,000 or $820,000 in total (the “Fox Meadows Construction Loans”). Each commitment is secured by a mortgage on a lot (numbers 1, 2, 3, and 4) in Block 1 of Fox Meadows 3^rd Addition and is also personally guaranteed by Mr. Krieger. Fox Meadows is a townhouse development located in Lakeville, Minnesota in which Cyclone owns 35 attached residential building sites. Proceeds of the Construction Loans will be used to construct the first four spec/model homes on Cyclone’s Fox Meadows property. Draws on the Construction Loans bear interest at the higher of: (a) 6.50% or (b) the prime rate as reported from time to time by The Wall Street Journal plus 3.00%. Interest only is payable monthly on the 10^th and the notes mature on May 21, 2015. The loans may be prepaid in whole or in part at any time without penalty. As of March 31, 2015, $662,000, was outstanding under the Fox Meadows Construction Loans.

On December 23, 2014, via an assignment and assumption agreement between Cyclone and Kenyon Holdings, LLC (“Kenyon”), a related party, Cyclone took ownership of a 10 acre parcel of undeveloped land located at 170xx Texas Avenue, Credit River Township, Minnesota and assumed a $120,000 note secured by a mortgage on the property and owed to Lakeview Bank (the “Lakeview Bank Mortgage”). Kenyon is owned by Timothy S. Krieger, the Company’s primary owner and its Chief Executive Officer, and Keith W. Sperbeck, its Vice President of Operations. The Lakeview Bank Mortgage bears interest at the highest prime rate reported as such from time to time by The Wall Street Journal. Interest only is payable monthly on the 25^th, the note matured on April 30, 2015, and the Company is currently waiting for the bank’s final approval to extend the note to April 30, 2016. The loan may be prepaid in whole or in part at any time without penalty.

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

Non-GAAP Financial Measures

Critical Accounting Policies and Estimates

Revenue Recognition and Commodity Derivative Instruments

Revenues in our wholesale trading business are derived from trading financial, physical, and derivative energy contracts while those for our retail segment result from electricity sales to end-use consumers. In our trading activities, contracts with the exchanges on which we trade permit net settlement, including the right to offset cash collateral in the settlement process. Accordingly, we net cash collateral against the derivative position in the accompanying consolidated balance sheets. All realized and unrealized gains and losses on derivative instruments are recorded in revenues. Revenue from the retail sale of electricity, including estimates of unbilled revenues for power consumed by customers but not yet billed under the cycle billing method, is recorded in the period in which customers consume the commodity, net of any applicable sales tax.

Hedge Accounting

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

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

Fair Value Measurements

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

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

Real Estate Development

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

Profits Interest Payments

Two of our second-tier subsidiaries (SUM and CEF) have Class B members. Under the terms of such subsidiaries’ member control agreements, Class B members have no voting rights, are not required to contribute capital, and have no rights to distributions following termination of employment, but are entitled to a defined share of profits while employed. Since Class B members have no corporate governance rights or risk of capital loss (or gain), they do not own non-controlling equity interests and profits interests payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the balance sheet.

For the quarters ended March 31, 2015 and 2014, we recorded $1,766,527 and $5,186,635, respectively, in salaries and wages and related taxes, representing the allocation of profits to Class B members. The amount of accrued profits interests included in accrued compensation at March 31, 2015 and 2014 was $1,766,527 and $5,227,234, respectively.

Item 3 - Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits.

We manage the commodity price risk of our retail load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges as well as in over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.

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

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

VaR is calculated daily, using positions and prices updated to the close of business on the previous day. The price history used is ideally that of the instrument held; however, in the cases where those prices are unavailable, benchmarking is used. Our VaR calculations always use the market value of the position, not its cost. In the case of a position where it is likely to take more than one day to close out, VaR is multiplied by the square root of the average days to liquidate the position in a stressed market.

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

The following table summarizes our liquid and illiquid VaR as of and for the three months ended March 31, 2015 and 2014:

					Increase (decrease)
	2015		2014		Units			Percent
Liquid VaR
As of March 31	$	342,488	$	525,893	$	(183,405	)		-34.9%
For the three months ended March 31:
Average	$	428,463	$	398,881	$	29,582			7.4%
Maximum		1,041,045		1,025,952		15,093			1.5%
Minimum		65,350		8,043		57,307			712.5%

VaR, pct of cash in trading accounts
As of March 31		3.12%		4.79%		-1.67	%		-34.9%
For the three months ended March 31:
Average (1)		3.90%		3.63%		0.27	%		7.4%
Maximum (1)		9.49%		9.35%		0.14	%		1.5%
Minimum (1)		0.60%		0.07%		0.52	%		712.6%

Illiquid VaR
As of March 31	$	2,183,094		na		na			na
For the three months ended March 31:
Average	$	3,130,229		na		na			na
Maximum		3,622,094		na		na			na
Minimum		2,183,094		na		na			na

VaR, pct of cash in trading accounts
As of March 31		19.89		na		na			na
For the three months ended March 31:
Average (1)		28.52		na		na			na
Maximum (1)		33.01		na		na			na
Minimum (1)		19.89		na		na			na

_______________

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

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

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

Percentage change in		Average percentage change in mark-to-market valuation (1)						Dollar change in mark-to-market valuation (1)
forward price from		Derivatives held		Economic		Cash flow		Derivatives held			Economic			Cash flow
March 31, 2015		for trading		hedges		hedges		for trading			hedges			hedges
	10%		-1851.3%		80.2%		42.2%		(493,424	)		138,725			178,060
	5%		-925.7%		40.1%		21.1%		(246,712	)		69,363			89,030
	1%		-185.1%		8.0%		4.2%		(49,342	)		13,873			17,806
	-1%		185.1%		-8.0%		-4.2%		49,342			(13,873	)		(17,806	)
	-5%		925.7%		-40.1%		-21.1%		246,712			(69,363	)		(89,030	)
	-10%		1851.3%		-80.2%		-42.2%		493,424			(138,725	)		(178,060	)

_______________

1 - Table includes only liquid positions

Interest Rate Risk

As of March 31, 2015, we had $3,760,000 of variable rate debt outstanding and at December 31, 2014, we had $1,635,000 of such debt outstanding. The interest rates charged on such are based in part on changes in certain market indices plus a credit margin, but are subject to “floors”, which may have the effect of converting variable rates to fixed rates and such was the case at March 31, 2015 and December 31, 2014. Consequently, at either date, we had no variable rate debt, although in the future we may be exposed to fluctuations in interest rates. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars, and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument.

Liquidity Risk

Liquidity risk arises from our general funding needs and the management of our assets and liabilities. We are exposed to additional collateral posting or margin requirements with the ISOs and exchanges if price volatility or levels increase. Based on a sensitivity analysis for positions under marginable contracts, a 20% change in electricity prices would cause an increase in margin collateral posted of approximately $353,000 as of March 31, 2015. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2015.

Wholesale Counterparty Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. We monitor and manage credit risk through the credit policies described in “Item 1 - Business – Wholesale Trading – Credit Risk Management” of our 2014 Form 10-K. Given the credit quality, diversification, and term of the exposure in the portfolio, we do not anticipate a material impact on financial position or results of operations from nonperformance by any counterparty.

Retail Customer Credit Risk

In our retail business, we may be exposed to certain customer credit risks. Although we are currently not exposed to retail customer credit risk to a large degree due to our participation in POR programs, we expect that this situation will change as we grow our retail business and expand into non-POR areas. Furthermore, economic and market conditions may affect our customers' willingness and ability to pay their bills in a timely manner, which could lead to an increase in bad debt expense above and beyond the allowance for uncollectible accounts charged to us by utilities. In general, we intend to manage retail credit risk as described in “Item 1 - Business – Retail Energy Services – Credit Risk Management” of our 2014 Form 10-K.

Foreign Exchange Risk

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

Item 4 - Controls and Procedures

The Company maintains a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of our disclosure controls and procedures as defined in Exchange Act Rules 13a-15(e) and 15d-15(e). Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2015, the Company’s disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There was no change in the Company’s internal control over financial reporting that occurred during the three months ended March 31, 2015 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II – Other Information

Item 1 - Legal Proceedings

See “Note 15 - Commitments and Contingencies” on page 30 of this Form 10-Q for a discussion of certain legal proceedings.

Item 1A - Risk Factors

No material changes from prior disclosure.

Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3 - Defaults Upon Senior Securities

None

Item 4 - Mine Safety Disclosures

None

Item 5 - Other Information

None

Item 6 - Exhibits

Exhibit Number		Description
10.1		Employment agreement, dated January 13, 2015 between Apollo Energy Services, LLC. and Mark A. Cohn (incorporated by reference to Exhibit 10.1 to the Registrant's Form 8-K filed January 22, 2015).
10.2		Fourth Amendment to Employment Agreement, dated January 21, 2015, between Twin Cities Power Holdings, LLC and Timothy S. Krieger (incorporated by reference to Exhibit 10.2 to the Registrant's Form 8-K filed January 22, 2015).
10.3		Federal Energy Regulatory Commission Letter Re: MISO Cinergy Hub Transactions (Twin Cities Power - Canada, Ltd., Twin Cities Energy, LLC, Twin Cities Power, LLC) Docket No. IN12-2-000, dated February 12, 2015 (incorporated by reference to Exhibit 10.1 to the Registrant's Form 8-K filed February 19, 2015).
10.4		Assignment of Employment Agreement between Stephanie Staska and Twin Cities Power Holdings, LLC, as amended, to Apollo Energy Services, LLC, dated January 1, 2015.
23.1		Consent of Baker Tilly Virchow Krause, LLP (incorporated by reference to Exhibit 21 to the Registrant's Form 10-K filed March 30, 2015).
31.1		Certification of Chief Executive Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2		Certification of Chief Financial Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
32.1		Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document
101.SCH		XBRL Schema Document
101.CAL		XBRL Calculation Linkbase Document
101.DEF		XBRL Definition Linkbase Document
101.LAB		XBRL Labels Linkbase Document
101.PRE		XBRL Presentation Linkbase Document

Signatures

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

		TWIN CITIES POWER HOLDINGS, LLC

		/s/ Timothy S. Krieger
Dated: May 15, 2015	By:	Timothy S. Krieger
		Chief Executive Officer, President and Chairman of the Board (principal executive officer)

		/s/ Wiley H. Sharp III
Dated: May 15, 2015	By:	Wiley H. Sharp III
		Vice President – Finance and Chief Financial Officer (principal accounting and financial officer)

Attached files

ASPIRITY HOLDINGS LLC Reports

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