UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, ~~2015~~2016

[ ]	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-~~203994~~179460

Aspirity Holdings, LLC

(Exact name of registrant as specified in its charter)

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

701 Xenia Avenue, Suite 475

Minneapolis, Minnesota 55416

(Address of principal executive offices, zip code)

(763) 432-1500

(Registrant’s telephone number, including area code)

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

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

$75,000,000

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

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

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

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 [ ] Accelerated filer [ ] Non-accelerated filer [ ] 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 [ ] No [X]

TABLE OF CONTENTS

Part I	4
Item 1 - Business	14
Definitions	14
Terms Specific to the Company	4
Industry Terms	5
Finance & Accounting Terms	7
Company Overview	8
The Restructuring	8
Industry Background	8
The U.S. Electric Power Industry	12
Key Strategies	10
Wholesale Electricity Markets	16
Sales & Marketing	12
Restructured Retail Electricity Markets	18
Energy Supply	14
Sales & Marketing	24
Credit Risk Management	15
Energy Supply	25
Financial Services	15
Credit Risk Management	25
Item 1A – Risk Factors	16
Competition	26
Item 1B – Unresolved Staff Comments	24
Seasonality	26
Item 2 – Properties	24
Personnel	26
Item 3 – Legal Proceedings	24
Regulatory Matters	26
Item 4 – Mine Safety Disclosures	24
Item 1A – Risk Factors	27
Part II	25
Item 1B – Unresolved Staff Comments	32
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 2 – Properties	32
Item 6 – Selected Consolidated Financial Data	25
Item 3 – Legal Proceedings	32
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation	26
Item 4 – Mine Safety Disclosures	32
Forward Looking Statements	26
Part II
The Company	27
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
Results of Operations	28
Use of Proceeds of Notes Offering	33
Liquidity, Capital Resources, and Cash Flow	32
Item 6 – Selected Consolidated Financial Data	34
Financing	36
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation	35
Non-GAAP Financial Measures	37
Forward Looking Statements	35
Critical Accounting Policies and Estimates	37
Important Note Regarding Recent Restructuring	36
Item 7A - Quantitative and Qualitative Disclosures about Market Risk	39
Operations Prior to the Restructuring	37
Item 8 – Financial Statements and Supplementary Data	40
Results of Operations	40
Reports of Independent Registered Public Accounting Firm	40
Liquidity, Capital Resources, and Cash Flow	46
Reports of Independent Registered Public Accounting Firms	41
Financing	48
Consolidated Balance Sheets	42
Non-GAAP Financial Measures	49
Consolidated Statements of Comprehensive Income	43
Critical Accounting Policies and Estimates	50
Consolidated Statements of Cash Flows	44
Item 7A - Quantitative and Qualitative Disclosures about Market Risk	52
Consolidated Statements of Changes in Members’ Deficit	46
Commodity Price Risk	52
Notes to Consolidated Financial Statements	47
Interest Rate Risk	54
Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	70
Liquidity Risk	54
Item 9B – Other Information	72
Credit Risk	54
Foreign Exchange Risk	54
Item 8 – Financial Statements and Supplementary Data	55
Management’s Report on Internal Controls over Financial Reporting	55
Report of Independent Registered Public Accounting Firm	56
Consolidated Balance Sheets	57
Consolidated Statements of Comprehensive Income	58
Consolidated Statements of Cash Flows	59
Consolidated Statements of Changes in Members’ Equity	61
Notes to Consolidated Financial Statements	62
Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	107
Item 9A - Controls and Procedures	107
Item 9B – Other Information	108
Part III
Item 10 – Directors, Executive Officers, and Corporate Governance	109
Directors and Executive Officers	109
Board Composition, Election of Directors, and Committees	111
Audit Committee	112
Compensation Committee	112
Investment Committee	112
Item 11 - Executive Compensation	113
Summary Compensation Table	113
Outstanding Equity Awards	113
Director Compensation	114
Retirement Plans	114
Potential Payments Upon Termination or Change-in-Control	115
Employment Agreements	115
Compensation Policies and Practices as They Relate to Risk Management	117
Indemnification of Directors and Executive Officers and Limitations of Liability	117
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	118
Item 13 – Certain Relationships, Related Transactions, and Director Independence	119
Item 14 – Principal Accountants’ Fees and Services	120
Audit and Non-Audit Fees	120
Audit Committee Pre-Approval Policies	120
Part IV
Item 15 – Exhibits, Financial Statement Schedules	121
Signatures	123
Exhibit 12.1 - Computation of Ratio of Earnings to Fixed Charges
Exhibit 12.2 - Computation of Ratio of Earnings to Fixed Charges and Preferred Distributions
Exhibit 21 - List of Subsidiaries of Registrant

iii

Part III	73
Item 10 – Directors, Executive Officers, and Corporate Governance	73
Directors and Executive Officers	73
Board Composition, Election of Directors, and Committees	74
Audit Committee	75
Compensation Committee	75
Investment Committee	75
Item 11 - Executive Compensation	76
Summary Compensation Table	76
Outstanding Equity Awards	77
Director Compensation	77
Retirement Plans	77
Potential Payments Upon Termination or Change-in-Control	78
Employment Agreements	78
Compensation Policies and Practices as They Relate to Risk Management	79
Indemnification of Directors and Executive Officers and Limitations of Liability	79
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	80
Item 13 – Certain Relationships, Related Transactions, and Director Independence	81
Item 14 – Principal Accountants’ Fees and Services	83
Audit and Non-Audit Fees	83
Audit Committee Pre-Approval Policies	83
Part IV	84
Item 15 – Exhibits, Financial Statement Schedules	84
Signatures	86
Exhibit 12.1 - Computation of Ratio of Earnings to Fixed Charges
Exhibit 12.2 - Computation of Ratio of Earnings to Fixed Charges and Preferred Distributions
Exhibit 21 - List of Subsidiaries of Registrant

iii

Part I

Item 1 - Business

Definitions

Terms Specific to the Company
Abbreviation or acronym		Definition
ABACCUS		The Annual Baseline Assessment of Choice in Canada and the United States is a study of U.S. states and Canadian provinces with respect to their efforts and achievements in the promotion of a competitive retail electric sector. The annual studies are prepared by DEFG, LLC, a management consulting firm specializing in energy
Aspirity or the Company		Aspirity Holdings, LLC and its subsidiaries, formerly known as Twin Cities Power Holdings, LLC or “TCPH”
AEMS		Aspirity Energy Mid States, LLC, a wholly owned subsidiary of Aspirity Energy
Aspirity Energy		Aspirity Energy, LLC, a first-tier subsidiary of Aspirity
AENE		Aspirity Energy Northeast, LLC, a wholly owned subsidiary of Aspirity Energy
AES		Aspirity Energy South, LLC, a first-tier subsidiary of Aspirity Energy and a second-tier subsidiary of the Company
AES		Aspirity Energy South, LLC, a wholly owned subsidiary of Aspirity Energy
Aspirity Financial		Aspirity Financial, LLC, a first-tier subsidiary of Aspirity
AESO		Alberta Electric System Operator, a statutory corporation of the Province of Alberta, is an ISO serving the Alberta Interconnected Electric System
Enterprises		Krieger Enterprises, LLC, a former first-tier subsidiary of Aspirity, the equity interests of which were distributed to the then members of the Company effective November 1, 2015
AOCI		Accumulated other comprehensive income
Apollo		Apollo Energy Services, LLC, a former first-tier subsidiary of the Company, then a first-tier subsidiary of Enterprises
Angell		Angell Energy, LLC, a Texas limited liability company that purchased TCP and SUM on June 1, 2015.
REH		Retail Energy Holdings, LLC, a former first-tier subsidiary of the Company, then a first-tier subsidiary of Enterprises. On November 2, 2016, Enterprises sold 100% of the equity interests of REH to Genie Retail Energy, a division of Genie Energy Ltd. (GNE - NYSE) for cash
Apollo		Apollo Energy Services, LLC, a wholly-owned, first-tier subsidiary of Krieger Enterprises, LLC
Distribution; Spinoff		The distribution of 100% of the equity of Enterprises to the then members of Aspirity – Timothy S. Krieger and Summer Enterprises, LLC. The date of the Distribution, also known as the “Spinoff”, is the date that the registration statement was declared effective by the SEC (November 12, 2015); for tax and accounting purposes, November 1, 2015.
ASC		Accounting Standards Codification
Exelon; PSA		Exelon Generation Company, LLC, a Pennsylvania limited liability company and wholly-owned subsidiary of Exelon Corporation. Exelon is the operator of the second largest electricity generation fleet in the U.S. On March 30, 2016, Exelon and Aspirity Energy entered into a 3 year, full requirements preferred supply agreement (“PSA”).
Aspirity or the Company		Aspirity Holdings LLC, formerly known as Twin Cities Power Holdings, LLC, and its subsidiaries
Legacy Businesses		The wholesale energy trading, real estate investments, investments in private companies, and legacy retail energy business operated by Enterprises, a former first-tier subsidiary of the Company.
Aspirity Energy		Aspirity Energy LLC, a wholly owned subsidiary of Aspirity
Notes; Notes Offering		The Company’s Renewable Unsecured Subordinated Notes issued pursuant to its ongoing “Notes Offering” or the direct public offering of the Company’s Notes pursuant to Registration Statements on Form S-1
Aspirity Financial		Aspirity Financial LLC, a wholly owned subsidiary of Aspirity
Operating Agreement		Aspirity’s Amended and Restated Operating Agreement dated March 30, 2016, as amended
ASU		Accounting Standards Update
Restructuring		The restructuring of the Company that was approved by the Board on May 27, 2015 and that effected the legal separation of the Legacy Businesses from the Company
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.
CEF		Cygnus Energy Futures, LLC, a wholly-owned subsidiary of CP and a second-tier subsidiary of Enterprises
CFTC		Commodity Futures Trading Commission, an independent agency of the United States government that regulates futures and option markets
CHP		Abbreviates “combined heat and power”, a type of generating facility
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 over-the-counter products and services

Abbreviation or acronym		Definition
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 Enterprises
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 Enterprises
Cyclone		Cyclone Partners, LLC, a wholly-owned, first-tier subsidiary of Enterprises
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”.
Distribution		That certain distribution of 100% of the equity of Enterprises to the members of Aspirity as the final step of the Restructuring.
Distribution Date		The date of the Distribution is the date that the registration statement was declared effective by the SEC (November 12, 2015); for tax and accounting purposes, November 1, 2015.
DOE		U.S. Department of Energy
EDC; LDC		Energy distribution company, may also be known as a local distribution company; see also “electric utility”
EDI compliant		In order for a licensed competitive electricity supplier to sell to, bill, and collect from retail customers within a given utility’s service territory, it must establish an electronic connection or become “EDI compliant” with such utility
EEI		The Edison Electric Institute is a trade association representing U.S. investor-owned electric companies. Its 160 U.S. operating utility and parent company members provide electricity for 220 million Americans, operate in all 50 states and the District of Columbia, and directly employ more than 500,000 workers. The association also has 70 international electric company members and 270 industry suppliers and related organizations as associate members

Abbreviation or acronym		Definition
EIA		Energy Information Administration, an independent agency within DOE
Electric utility		A corporation, person, agency, authority, or other legal entity or instrumentality aligned with distribution facilities for delivery of electric energy for use primarily by the public such as investor-owned utilities (“IOUs”), municipally-owned utilities (“munis”), utilities owned by states or political subdivisions thereof (“POUs”), federal utilities, and rural electric cooperatives (“co-ops”). A few entities that are tariff based and corporately aligned with companies that own distribution facilities are also included.
Enterprises		Krieger Enterprises, LLC, a former first tier subsidiary of Aspirity, the equity interests of which were distributed to the then members of the Company on the Distribution Date
ERCOT		Electric Reliability Council of Texas, an ISO managing about 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
Exelon		Exelon Generation Company, LLC, a Pennsylvania limited liability company and wholly-owned subsidiary of Exelon Corporation
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission, an independent regulatory agency within DOE
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, Inc. is the leading global network of regulated exchanges and clearing houses 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.
IPP		An “independent power producer” or IPP is a corporation, person, agency, authority, or other legal entity or instrumentality that owns or operates facilities for the generation of electricity for use primarily by the public and that is not an electric utility.

Abbreviation or acronym		Definition
ISO; RTO		An Independent System Operator or “ISO” is 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. A Regional Transmission Organization or “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. ISOs and RTOs are collectively referred to as ISOs.
ISO-NE		ISO New England Inc., an RTO serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont
Legacy Businesses		The wholesale energy trading, real estate investments, investments in private companies, and legacy retail energy business operated by Enterprises, a former first tier subsidiary of the Company
LMP		One of the unique aspects of FERC-regulated wholesale electricity markets is the availability of “locational marginal prices” or “LMPs”. The theoretical price of electricity at each node on a network is calculated based on the assumptions that one additional megawatt-hour of energy is demanded at the node in question, and 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.
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.
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
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.
S-1, Old and New		The Company’s Registration Statement on Form S-1, declared effective by the Securities and Exchange Commission on November 12, 2015 with respect to the Notes Offering is defined as the “New S-1”, while that declared effective on May 10, 2012 is defined as the “Old S-1”
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.

Terms Specific to the Company
Abbreviation or acronym		Definition
NOAA		National Oceanic and Atmospheric Administration, an agency of the U.S. Department of Commerce
S-1; Old and New		The Company’s Registration Statements on Form S-1. The statement declared effective by the SEC on November 12, 2015 is defined as the “New S-1”, while that declared effective on May 10, 2012 is defined as the “Old S-1”
Noble		Noble Conservation Solutions, Inc., a Minnesota corporation. On September 1, 2015, Enterprises purchased 60% of the outstanding shares of Noble.
Term Loan		Term Loan Agreement between Aspirity Financial as lender and Enterprises as borrower dated July 1, 2015, as amended on November 1, 2015, January 27, 2016, and November 1, 2016. Pursuant to the Term Loan, Enterprises borrowed $22,206,000 from Aspirity Financial with final maturity date of December 30, 2019
Notes		The Company’s Renewable Unsecured Subordinated Notes issued pursuant to its ongoing Notes Offering
Term Loan Notes		Each of the Company’s Notes outstanding as of June 30, 2015, including any renewals thereof
Notes Offering		The direct public offering the Company’s Notes pursuant to Registration Statements on Form S-1
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
Operating Agreement		Aspirity’s Amended and Restated Operating Agreement dated March 30, 2016
Prospectus		That prospectus dated November 12, 2015 as part of the New S-1, as supplemented from time to time
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
PSA		A “preferred supply agreement”
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. As renewable generators produce electricity, they create one REC per megawatt-hour. If the physical electricity and the associated RECs are sold to separate buyers, the electricity is no longer considered “renewable” or “green” as the REC is what conveys the attributes and benefits of the renewable electricity, not the electricity itself
REH		Retail Energy Holdings, LLC, a wholly-owned, first-tier subsidiary of Enterprises

Industry Terms
Abbreviation or acronym		Definition
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

EDC; LDC		“Electric distribution company” or “energy distribution company”; may also be known as a “local distribution company”; see also “electric utility”

EDI compliant		For a licensed competitive electricity supplier to sell to, bill, and collect from retail customers within a given utility’s service territory, it must establish an electronic connection or become “EDI compliant” with such utility

EIA		Energy Information Administration, an independent agency within the U.S. Department of Energy

Electric utility; IOU; muni; POU, co-op		A corporation, person, agency, authority, or other legal entity or instrumentality aligned with distribution facilities for delivery of electric energy for use primarily by the public such as investor-owned utilities (“IOUs”), municipally-owned utilities (“munis”), utilities owned by states or political subdivisions thereof (“POUs”), federal utilities, and rural electric cooperatives (“co-ops”). A few entities that are tariff based and corporately aligned with companies that own distribution facilities are also included

Electric supplier		A natural person or legal entity licensed by a governmental authority to sell electricity on a competitive basis within its jurisdiction; depending upon the jurisdiction may also be known as an Alternative Retail Electric Supplier (“ARES”), Competitive Electricity Provider (“CEP”), Competitive Retail Electric Service Provider (“CRES”), Electric Generation Supplier (“EGS”), Energy Service Company (“ESCO”), Generation and Transmission Supplier (“G&T Supplier”), Non-regulated Power Producer (“NPP”), Retail Electric Provider (“REP”), Retail Electric Supplier (“RES”), or Third Party Supplier (“TPS”)

Industry Terms
Abbreviation or acronym		Definition
Restructuring		The restructuring of the Company that was approved by the Board on May 27, 2015 and was completed effective November 1, 2015 and effected the legal separation of the Legacy Businesses from the Company
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
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
FERC; DOE		Federal Energy Regulatory Commission, an independent regulatory agency within the U.S. Department of Energy (“DOE”)
SUM		Summit Energy, LLC, a wholly-owned subsidiary of TCP
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.
TCE		Twin Cities Energy, LLC, an inactive, wholly-owned, first-tier subsidiary of Enterprises
ISO-NE		ISO New England Inc., an RTO serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont
TCP		Twin Cities Power, LLC, formerly, a wholly-owned, first-tier subsidiary of the Company
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
TCPC		Twin Cities Power – Canada, Ltd., an inactive, wholly-owned subsidiary of TCE and a second-tier subsidiary of Enterprises
NYISO		New York Independent System Operator, an ISO serving New York state
TCPH		Twin Cities Power Holdings, LLC
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.
Term Loan		Term Loan Agreement between Enterprises as borrower and Aspirity Financial as lender dated July 1, 2015, as amended on November 1, 2015 and January 27, 2016. Pursuant to the Term Loan, Enterprises borrowed an aggregate principal amount of $22,206,000 from Aspirity Financial.
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.
Term Loan Notes		Each of the Company’s Notes outstanding as of June 30, 2015 in an aggregate principal amount of $22,206,000, including any renewals of such Notes
PURPA		Public Utilities Regulatory Policy Act of 1978
TSE		Town Square Energy, initially, an accounting division of TCP resulting from the acquisition of the business and assets of Community Power & Utility, LLC on June 29, 2012. 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
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. As renewable generators produce electricity, they create one REC per megawatt-hour. If the physical electricity and the associated RECs are sold to separate buyers, the electricity is no longer considered “renewable” or “green” as the REC is what conveys the attributes and benefits of the renewable electricity, not the electricity itself
TSEC		Town Square Energy Canada, Ltd, a wholly-owned subsidiary of REH and a second-tier subsidiary of Enterprises
TSEE		Town Square Energy East, LLC, formerly known as Discount Energy Group, LLC (“DEG”), a wholly-owned subsidiary of REH and a second-tier subsidiary of Enterprises
Ultra Green		Ultra Green Packaging, Inc. 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.
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.

Abbreviation or acronym		Definition
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 also known as 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:

Finance & Accounting Terms
Abbreviation or acronym		Definition
ASC		Accounting Standards Codification

ASU		Accounting Standards Update

CFTC		Commodity Futures Trading Commission, an independent agency of the United States government with primary responsibility for regulating futures and options markets

FASB		Financial Accounting Standards Board

GAAP		Generally accepted accounting principles in the United States

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

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

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

Company Overview

Aspirity ~~Holdings (the “Company” or “Aspirity”), formerly known as Twin Cities Power Holdings,~~ is a holding company that conducts its operations principally through wholly-owned subsidiaries. WeOur ~~currently~~roots ~~have~~go ~~two~~back ~~direct~~to ~~operating~~2005 ~~subsidiaries,~~and ~~Aspirity~~in ~~Energy,~~2015 ~~which~~we ~~houses~~restructured. aThis ~~start-up~~restructuring ~~retail~~included ~~energy~~the ~~business,~~sale ~~and~~of ~~Aspirity~~a ~~Financial,~~subsidiary ~~which~~and ~~was~~the ~~formed~~spinoff toof ~~provide~~Enterprises ~~energy-related financial~~and ~~services~~its tolegacy ~~businesses~~business segments ~~and~~of ~~households.~~wholesale ~~Both~~trading, ~~subsidiaries~~diversified ~~are~~investments, ~~Minnesota~~and ~~limited~~the ~~liability~~retail ~~companies~~business asoperated isby ~~the Company~~REH.

~~In 2015~~Today, we ~~restructured~~have astwo ~~more~~first-tier ~~fully~~operating ~~described~~subsidiaries ~~below.~~- ~~The~~Aspirity ~~Restructuring~~Energy ~~included~~in ~~the~~retail ~~sale~~energy ofservices ~~two~~and ofAspirity ~~our~~Financial ~~wholesale~~which ~~trading~~provides energy-related financial services to businesses and households. Even though the ~~spin-off~~Company ofhas ~~Krieger~~existed ~~Enterprises~~since 2005, ~~incorporating~~since ~~our~~the ~~three~~restructuring in ~~legacy~~2015 ~~business~~the ~~segments~~Company –has ~~wholesale~~operated ~~trading,~~as ~~retail~~a ~~energy services,~~start-up and ~~diversified~~our ~~investments~~financial results for 2015 and 2016 reflect that status.

AsIndustry a result, we currently have limited operations and assets although we are largely isolated from the inherent earnings volatility and regulatory exposure associated with the wholesale electricity markets.Background

By virtually any measure, the ~~end~~electric ofpower ~~2016,~~industry ~~our~~in ~~goal~~the U.S. is tosubstantial. bePer ~~able~~preliminary toEIA ~~market~~data ~~power~~released toon ~~approximately~~February 3824, 2017 ~~million~~in ~~residential~~the ~~customers~~Electric ~~located~~Power Monthly, in 502016, ~~service areas~~the industry sold 3,710 TWh (down 1.3% from 3,759 TWh in ~~the~~2015) 14for ~~jurisdictions~~more ~~that~~than $381.4 ~~allow~~billion ~~all~~(down ~~retail~~2.5% from $391.3 billion) to over 150.0 million residential, commercial, and industrial customers (up 0.7% from 149.8 million) for an average price of ~~investor-owned~~10.28 ~~utilities~~cents/kWh, todown ~~choose~~1.2% ~~who~~from ~~supplies~~10.41 ~~them~~cents/kWh ~~with~~in ~~electricity~~2015.

~~Until~~Electric ~~our~~power ~~retail~~in commercial quantities, unlike other energy ~~business~~commodities ~~has~~such ~~gained~~as ~~scale,~~coal ~~our~~or ~~primary~~natural ~~sources~~gas, ofcannot ~~cash~~be ~~flow~~stored, ~~will~~i.e., the supply must be ~~Note~~produced ~~sales~~or ~~and~~generated ~~loan~~exactly ~~payments~~when ~~received~~used or demanded by customers. Further, the laws of physics dictate that power flows ~~Aspirity~~within ~~Financial~~a ~~from~~network ~~Enterprises~~along the lines of least resistance, ~~our~~not ~~first~~necessarily ~~financial~~where ~~services~~we ~~customer~~may want it to go. These facts, coupled with the essential nature of the service to modern life, have obvious implications for electricity market structures and regulations.

WeToday, ~~are~~the ~~headquartered~~industry atincludes ~~701~~any ~~Xenia~~entity ~~Avenue~~producing, ~~South~~distributing, ~~Suite~~trading, ~~475~~or selling electricity. Power marketers and retail energy providers do not own any generation, ~~Minneapolis~~transmission, MNor ~~55416~~distribution assets, ~~telephone~~but ~~(763)~~buy ~~432-1500~~and sell in wholesale and retail markets. Finally, participants in wholesale power markets include investment banks, hedge funds, private equity firms, and proprietary traders.

The Restructuring

Net Summer Capacity in Gigawatts of U.S. Utility Scale Generating Units by Technology
	At				Year-to-year change
Technology	Dec 2016		Dec 2015		Units			Percent

Renewable sources		199.4		182.5		16.9			9.2	%
Fossil fuels		755.9		758.5		(2.6	)		-0.3	%
Hydroelectric pumped storage		22.7		22.6		0.1			0.4	%
Other energy storage		0.6		0.3		0.2			74.7	%
Nuclear		99.3		98.7		0.6			0.7	%
All other sources		1.5		1.5		0.0			1.6	%

All sources		1,079.4		1,064.1		15.3			1.4	%

~~For~~Source: ~~some time~~EIA, ~~the~~Electric ~~Company~~Power ~~had~~Monthly, ~~been~~published ~~considering~~February ~~ways to access the public equity markets. In order to be successful in reaching this goal~~24, ~~management and the Board concluded that:~~2017.

●Physically, the ~~Public~~nation’s ~~equity~~power ~~markets~~system ~~value~~includes ~~stability~~generation, transmission, and ~~predictability~~distribution ~~of earnings~~systems. ●Participants ~~There~~in ~~are~~the ageneration ~~handful~~segment include ofinvestor-owned, publicly-owned, ~~traded~~cooperative, ~~retail energy companies~~ and nofederal ~~publicly traded wholesale energy trading businesses. ● Retail energy companies tend to be valued on a per customer basis~~utilities, ~~with~~and ~~recent transactions occurring at prices ranging from $200~~non-~~$500~~utility ~~per~~power ~~customer. ● Combining a proprietary wholesale trading operation with a retail energy business results in a reduced overall valuation~~producers, asincluding ~~the~~independent power ~~market~~producers ~~generally~~and ~~assigns~~commercial ~~little~~and ~~value~~industrial toentities ~~trading~~that ~~profits~~operate ~~due~~co-generation ~~to their extreme volatility~~facilities. ●As ~~While~~of ~~wholesale~~the ~~electricity~~end ~~trading~~of ~~makes for a good private equity investment~~2016, the ~~earnings~~net ~~volatility~~summer capacity ~~and~~of ~~regulatory exposure endemic to~~ the ~~business~~nation’s ~~make~~utility-scale itgenerating ~~unattractive~~units aswas a1,079.4 ~~publicly~~GW, ~~traded~~up ~~equity~~1.4% ~~For~~from ~~example,~~December ~~on August 29~~31, ~~2014,~~2015. ~~FERC~~In ~~commenced~~addition ~~a regulatory action in PJM seeking~~ to ~~retroactively~~generation, the ~~impose new fees - in still to be determined amounts - on trades in PJM~~nation’s ~~up-to-congestion~~bulk ~~product.~~power ~~Since~~system ~~the~~also ~~announcement~~includes ofabout ~~the proceeding~~200,000 ~~UTC~~miles ~~trading volume has decreased substantially and a number~~ of ~~companies~~high-voltage ~~have~~(over ~~exited~~144kV) ~~the~~transmission ~~market1~~lines. ● The ~~cash flow of~~ retail distribution ~~energy~~network ~~and~~includes ~~financial~~substations, ~~services~~wires, ~~businesses~~poles, ~~are generally much more stable than those of wholesale trading~~metering, ~~as each customer represents a reasonably predictable revenue stream~~billing, ~~either~~and ofrelated ~~energy~~support ~~sales or interest income~~systems.

~~Consequently,~~The ~~and~~investor-owned asportion ~~a result~~ of ~~these~~the ~~conclusions~~industry, toincluding ~~effect~~utilities, ancompetitive ~~initial~~retail ~~public~~energy ~~offering of its common equity~~providers, ~~the~~and ~~Company~~non-utility ~~would need to be~~generators, ~~restructured~~constitutes ~~and~~over ~~recast.~~70% ~~During~~of ~~May 2015,~~ the ~~Company~~industry’s ~~developed~~revenues, ~~plans~~unit tosales, ~~separate its Legacy Businesses from a proposed retail energy~~ and ~~financial services business~~customers. ~~The~~Since ~~Restructuring~~the ~~was~~passage ~~designed~~of ~~so that Aspirity (~~the ~~publicly~~Public ~~reporting~~Utilities ~~company) would~~Regulatory ~~hold~~Policy ~~new~~Act ~~retail~~of ~~energy~~1978, ~~and financial services businesses while Enterprises would continue to operate~~ the ~~more~~industry ~~volatile~~has ~~Legacy Businesses~~been asundergoing a ~~private~~massive ~~company.~~restructuring Atprocess athat ~~special~~has ~~meeting~~had onparticular ~~May~~impact ~~27,~~on ~~2015, the Board gave management the authorization to proceed~~investor-owned ~~with the Restructuring~~utilities.

~~The~~Since ~~restructuring~~PURPA, ~~plan~~the ~~called~~nation ~~for:~~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 many of the nation’s bulk power systems are operated under the supervision of FERC, an independent agency within the DOE. Furthermore, while some states have restructured their markets such that individual consumers may choose their electricity supplier, most state public utility commissions continue to regulate their utilities under the traditional cost-based framework.

●Today, ~~The~~wholesale ~~formation~~prices are subject to a federal regulatory framework focused on ensuring fair competition and reliability of ~~Aspirity~~supply. ~~Energy~~At the state level, ~~Aspirity~~under ~~Financial~~the traditional system which most states continue to employ, a vertically integrated utility is responsible for serving all consumers in a defined territory and ~~Krieger~~customers ~~Enterprises~~are asobligated ~~first~~to ~~tier~~pay ~~subsidiaries~~the regulated rate for their class of service. However, in a state with a restructured or deregulated market, the ~~Company;~~generation, ●transmission, ~~The~~distribution, ~~sale~~and retail marketing functions of ~~TCP2;~~the ●industry are legally separated and pricing of energy is unbundled from delivery services to bring the benefits of competition to retail customers. The ~~transfer~~regulated portions of ~~all~~these ~~legacy~~formerly ~~businesses~~vertically-integrated utilities, ~~operations~~now generally known as EDCs or LDCs, are responsible for delivering power, billing consumers, and ~~private~~resolving ~~investment~~any ~~assets~~service issues, but customers can shop around and ~~directly~~buy ~~associated~~power ~~liabilities~~from toany ~~Enterprises.~~licensed ~~The~~supplier ~~Company’s~~or ~~Legacy~~broker ~~Businesses~~doing ~~included:~~business in the state, hence retail choice.

●Today, years Aafter ~~wholesale~~Massachusetts ~~segment~~and ~~trading~~Rhode ~~virtual~~Island ~~electricity~~became ~~and~~the ~~energy-based~~first ~~derivatives~~states ~~contracts~~to effectively implement choice in ~~North~~1998, ~~American~~14 ~~markets~~full ~~regulated~~choice jurisdictions by- ~~FERC~~13 ~~and~~states plus the ~~CFTC;~~District ●of AColumbia ~~retail~~- ~~energy~~allow ~~business~~all ~~providing~~residential, ~~electricity~~commercial, ~~supply~~and ~~services~~industrial customers served by investor-owned utilities to ~~residential~~choose ~~and~~their ~~small~~energy ~~business~~provider. Generally, only customers inof 8IOUs ~~states~~are ~~that~~eligible ~~permit~~to ~~retail~~choose ~~choice;~~their ~~and~~electric supplier ●while ~~Certain~~those ~~asset~~served ~~management~~by ~~activities~~a municipal, ~~including~~cooperative, ~~real~~or ~~estate~~other ~~development~~type of non-investor owned utility are ineligible. However, there are certain areas where customers of specific cooperatives and ~~investments~~public inutilities ~~privately~~may ~~held~~have ~~businesses;~~choice but these instances are rare.

●	The creation of a Term Loan between Financial as lender and Enterprises as borrower3;
●	A name change from Twin Cities Power Holdings to Aspirity Holdings to reflect the new focus

1	The Company’s former subsidiary, Twin Cities Power, and its subsidiary, Summit Energy (collectively, “TCP”) were active traders of UTCs.
2	On June 1, the Company closed on the sale of TCP to Angell. The sale price was initially $20.7 million, paid in the form of $500,000 cash and a $20.2 million, 3 year secured note bearing 6.00% interest and payable quarterly. Effective September 1, the purchase price was adjusted to $15.0 million due to the return of TCP’s Minnesota operations to Enterprises. The note amount and amortization period were amended to $15.02 million and 4 years. The gain on sale is being recognized as payments on the note are collected. In selling TCP, the Company partially accomplished its goal of reducing its regulatory exposure and earnings volatility.
3	Although initially an intercompany relationship, the loan between Enterprises and Aspirity Financial closed on July 1, is constructed on an arm’s length basis, and ensures that the cash flows generated by the Legacy Businesses are used to pay interest and principal on a substantial portion of the Notes. Accordingly, the Term Loan initially reflected the outstanding principal amount ($22.2 million) and weighted average interest rate (14.08%) of the Notes as of Jun 30, 2015, with a final maturity date of December 30, 2019. Further, subject to true-ups for actual Note redemptions and interest paid, the monthly repayment schedule provides for payment by Enterprises of maximum possible redemptions and interest.

●Per analysis ~~The~~of ~~distribution~~EIA ordata ~~spin-off~~for ofstates ~~100~~with restructured markets, on average between 2002 and 2014, energy and delivery costs accounted for about 67% and 33%, respectively, of the ~~common~~average ~~equity~~retail ~~interests~~electricity inprice. ~~Enterprises~~Of tocourse, ~~Timothy~~these ~~Krieger~~percentages ~~(99.50%~~fluctuate ~~owner)~~from ~~and~~year to ~~Summer~~year ~~Enterprises~~and ~~(0.50%~~state ~~owner)~~to state, ~~subject~~primarily due to: wholesale energy market conditions, weather, and state rules.

●In any ~~Determination~~case, ~~that~~restructuring ~~the~~created ~~transaction~~new ~~would~~business beopportunities ~~tax-free;~~in ●an ~~The~~established ~~approval~~industry. In general, there are two types of non-utility businesses participating in the ~~holders~~deregulated ofretail aenergy ~~majority~~marketing offunction in the ~~Notes[4]~~U.S. ~~This~~today ~~occurred~~– ~~June~~brokers 26and suppliers – but each state licenses these businesses in a different way. For example, ~~2015;~~not every jurisdiction makes a broker/supplier distinction and ●some ~~The~~divide ~~declaration~~licenses ofbased ~~effectiveness~~on ofpotential ~~the~~customer ~~Company’s~~categories ~~New~~such Sas “residential” or “non-1residential” while byother ~~the~~states ~~SEC[5]~~divide their markets based on historical utility service territories and license an entity to only provide services in a specific area. ~~This~~Overall, ~~occurred~~as ~~November~~of 12January 2014, ~~2015;~~there ~~and~~were about 700 of these licensed retail energy businesses in the U.S.

●Brokers, also ~~Concurrently~~known ~~with~~as ~~the~~aggregators, ~~Distribution~~negotiate ~~Date~~supply agreements between retail customers, ~~certain~~typically ~~executive~~large ~~management~~commercial ~~changes~~or industrial entities, and wholesale suppliers. Brokers collect commissions from the supplier that wins a ~~plan~~piece of business. Brokers do not bill customers directly and never take title to ~~add~~energy; they work for the customer. Their major expense is signing up new ~~common~~customers. As ~~equity~~a ~~owners~~result, ~~ultimately~~brokers ~~decreasing~~generally ~~Mr.~~have ~~Krieger’s~~relatively ~~common~~limited ~~equity~~margins ~~interest~~but inhigh ~~the~~quality ~~Company~~cash toflows ~~45%~~and comparatively small balance sheets.

AsCompetitive ~~shown~~electric bysuppliers, ~~the~~also ~~chart~~known ~~below~~as REPs, ~~prior~~ESCOs, toARES, or the ~~start~~like ofdepending upon the ~~Restructuring~~state, onare ~~May~~also ~~31,~~licensed ~~2015,~~to ~~the~~deal ~~Company’s~~with ~~active~~retail customers. ~~first~~They ~~tier~~have ~~subsidiaries consisted~~an ofup-stream ~~Apollo,~~supply ~~TCP~~arrangement which may include purchasing directly from an ISO like ERCOT, ~~CTG~~MISO, ~~Cygnus~~PJM, or ~~REH~~NYISO or bilaterally from large energy companies or independent power producers. In contrast to brokers, suppliers potentially have higher margins on the energy sold but require larger amounts of capital to acquire energy and ~~Cyclone~~carry receivables and payables for some period.

Under the terms of the Indenture governing the Notes, the disposition of all or substantially all of the Company’s assets requires the approval of the holders of a majority of Notes by principal amount. Consequently, on June 3, 2015, a proposal was submitted to the holders of the $21.9 million of Notes outstanding as of May 27, 2015 asking them to approve the transfer of the Legacy Businesses. Noteholders were asked to vote YES or NO to the proposal by June 26, 2015 with an abstention counting as a NO. The Company received YES votes from holders of $15.0 million, representing 68.6% of total Notes outstanding and 137% of the number required to pass the measure. Holders of $202,000 voted NO and $6.7 million abstained.

For tax and accounting purposes, November 1, 2015 is considered to be the Distribution Date.

Key Strategies

It is important to note that while we and REH, a former wholly-owned subsidiary of Enterprises sold on November 2, 2016, both compete in the same industry, Aspirity Energy was formed to pursue different supply and marketing strategies than those employed by REH.

For example, with respect to supply, Aspirity has chosen to procure the energy required by its customers using a “full requirements” preferred supply agreement that while costing slightly more, eliminates volumetric, commodity price, and liquidity risks. REH buys the energy it needs using a cash-intensive, trading-centric model that results in relatively unpredictable costs.

With respect to marketing, Aspirity offers only long term, fixed rate electricity contracts and ultimately intends to offer other energy and home management related goods and services as well, hence our slogan, Power + More, with the goal of building a brand characterized by long term relationships. These long-term relationships will be fostered by offering products and services other than just electricity – hence the ‘+ More’ of our slogan. Certain products and services are currently being vetted and we expect to begin offering some in 2017. Further, Aspirity goes to market via multiple offline and online channels such as door-to-door, outbound telemarketing, paid search, and direct mail. In contrast, REH offers principally shorter term contracts and competes primarily on price. It offers its services almost exclusively online via state-run comparison shopping engines in 8 states.

~~The~~Since ~~chart~~the ~~below~~sale ~~reflects~~of ~~the~~electricity ~~organizational~~is ~~structure~~a ~~and~~regulated business, ~~lines~~we ofcan ~~the~~only ~~Company~~market onin ~~October~~jurisdictions ~~31,~~where ~~after~~we ~~the~~are ~~formation~~licensed ofby ~~the~~appropriate authorities ~~Aspirity~~and ~~operating~~have ~~companies,~~established ~~the~~electronic ~~sale~~connections ofor ~~TCP,~~“EDI compliance” with relevant utilities to exchange customer usage and ~~the~~billing ~~contribution~~information. ofOur goal is to become licensed in all full choice jurisdictions and become EDI compliant with the ~~legacy~~larger IOUs ~~businesses~~in such areas. When this “market portfolio” is available to ~~Enterprises~~us, ~~but~~we ~~before~~may ~~its~~quickly ~~spin-off~~shift our marketing resources and budget from area to area based on ~~the~~which ~~Distribution~~opportunities ~~Date:~~are most attractive.

AsLike ~~shown~~most ~~below~~startups, ~~after~~we ~~the~~have ~~Restructuring~~experienced both success and ~~distribution~~challenges ofto ~~Enterprises,~~date. ~~the~~While ~~Company~~we ~~has~~began ~~operations~~to inacquire ~~two~~customers ~~business~~in ~~segments.~~January ~~Note~~2016, we ~~that~~have ~~under~~also ~~the~~experienced ~~terms~~delays ofversus ~~the~~our ~~PSA~~original ~~with~~timetable, ~~Exelon~~principally in obtaining licenses and structuring our online presence. In addition, weour ~~have~~former ~~agreed~~CEO toleft ~~merge~~us ~~AEMS~~in ~~and~~July ~~AENE~~2016 ~~into~~for ~~Aspirity~~health ~~Energy~~reasons.

In any case, as of December 31, 2016, we held market-based rate authority from FERC, were members of the ISO-NE and PJM wholesale electricity markets, were licensed to serve retail customers in Illinois, Maryland, New York, Ohio, Pennsylvania, and Rhode Island, had established electronic connections with 9 IOUs serving over 10 million residential accounts, and were providing electricity to over 7,000 households.

By the end of 2017, our goal is to be able to market power to the approximately 32 million residential customers located in the service areas of 40 or so IOUs in all 14 full choice jurisdictions.

AsOur amarket ~~result~~rollout plan as of ~~the~~March ~~Restructuring~~23, we2017 ~~currently~~is ~~have~~summarized ~~limited~~in ~~operations~~the ~~and~~table ~~limited assets~~below. WeNote ~~are~~that ~~developing~~delays ~~our~~to ~~new~~this ~~retail~~schedule ~~energy business,~~may occur and ~~while~~such wemay ~~are~~have ina ~~the~~material ~~process~~impact ofon ~~applying~~our ~~for~~business. ~~licenses~~Further, ~~and~~the ~~EDI~~table ~~compliance~~includes inNew ~~all~~York. 14While ~~jurisdictions and with 50 investor owned utilities serving about 38 million residential accounts,~~ we ~~began~~intend to ~~offer~~join ~~service~~NYISO ~~in late January 2016~~ and ~~are essentially~~qualify ato ~~start-up.~~do ~~Until our retail energy~~ business iswith ~~generating~~the ~~significant~~6 ~~revenue,~~IOUs ~~our~~serving ~~primary~~the ~~sources~~state’s ~~of cash flow will be loan payments received by Aspirity Financial from Enterprises and note sales~~5.8 Inmillion ~~addition~~residential ~~to building the Aspirity Energy business~~accounts, we ~~may~~currently ~~also~~do ~~decide~~not toanticipate ~~lend~~entering those ~~additional~~markets ~~funds~~due to ~~Enterprises,~~regulatory asuncertainty ~~well~~with asrespect ~~other~~to ~~companies in~~ the ~~power~~contracts ~~sector,~~that anmay ~~industry~~be insold ~~which we have significant experience~~there.

~~The~~Aspirity ~~U.S. Electric Power Industry~~Energy

ByMarket ~~virtually~~Rollout ~~any~~Plan ~~measure,~~by the electric power industry in the U.S. is substantial. According to EIA data, in 2014, the most recent year for which full data is available, the industry sold 3,765 TWh (up 1.1% from 2013) for more than $393.1 billion (up 4.6%) to over 147.3 million residential, commercial, and industrial customers (up 0.7%).Quarter

~~Electric~~Last ~~power~~updated inMarch ~~commercial quantities~~23, unlike other energy commodities such as coal or natural gas, cannot be stored, i.e., the supply must be produced or generated exactly when used or demanded by customers. Further, the laws of physics dictate that power flows within a network along the lines of least resistance, not necessarily where we may want it to go. These facts, coupled with the essential nature of the service to modern life, have obvious implications for electricity market structures and regulations.2017

Today, the industry includes any entity producing, distributing, trading, or selling electricity. Physically, the nation’s power system includes generation resources, transmission lines, and retail distribution systems. As of the end of 2014, participants in the generation segment of the industry included investor-owned, publicly-owned, cooperative, and federal utilities, and non-utility power producers, including independent power producers and commercial and industrial entities that operate co-generation facilities, also known as CHP or combined-heat-and-power plants. These entities owned over 19,700 generating units with total nameplate capacity of 1,172 GW incorporated into over 7,600 power plants. In addition to generation, the nation’s bulk power system also includes about 200,000 miles of high-voltage (over 144kV) transmission lines. Our retail distribution network includes substations, wires, poles, metering, billing, and related support systems. Power marketers and retail energy providers do not own any generation, transmission, or distribution assets, but buy and sell in wholesale and retail markets. Finally, participants in wholesale power markets include banks, hedge funds, private equity firms, and trading houses.

	ISOs			States			EDI Ready IOU Service Areas			Accessable Customers (000s)
Period		Added during period	Available at end of period		Added during period	Available at end of period		Added during period	Available at end of period		Added during period	Available at end of period

Q4 2015		1	1		2	2		0	0		0	0

Q1 2016		0	1		1	3		3	3		4,537	4,537
Q2 2016		1	2		1	4		3	3		3,924	8,461
Q3 2016		0	2		2	6		3	3		1,848	10,308
Q4 2016		1	3		0	6		4	4		2,028	12,337

Q1 2017		0	3		2	8		1	1		528	12,864
Q2 2017		1	4		4	12		15	15		11,358	24,222
Q3 2017		0	4		0	12		5	5		5,959	30,181
Q4 2017		0	4		0	12		0	0		0	30,181

Totals		4	—		12	—		34	—		30,181	—

\Despite the challenges we have encountered, which are not unusual for a start-up company, we believe that our marketing approach and the advantages of our power supply agreement with Exelon provide positive indications for our future development.

Sales & Marketing

The retail energy sales cycle starts with a sign-up on day 1 and most enrollees start receiving electricity from us about day 30. There is additional time between the end of the customer’s first billing cycle with us on about day 60, billing on day 61, payment to the utility on or about day 81, and payment by the utility to us about day 90 or so. Once this start-up period has been completed, we expect to collect cash from a customer every 30 days or so. As a retailer’s customer base grows, this delay between signup and first cash collection may put stress on its cash position.

All payments from customers go to a lockbox operated by our energy supplier, Exelon, with funds collected during a given month released to us during the first week of the next month. While our agreement with Exelon allows us to defer payment for energy sold, we are still required to pay our marketing vendors for the enrollees they sign, typically twice a month.

Our services are made available to customers under fixed price contracts as well as some that may provide for renewable energy percentages greater than state requirements. All contracts regardless of price, term, and renewable energy percentage are subject to standard terms and conditions as filed from time to time with state regulatory authorities.

Retail customers make purchase decisions based on a variety of factors, including price, customer service, brand, product choices, bundles, or value-added features. On average, only about 36% of the 32.2 million residential customers (in a range of 7% to 81%) in our 44 target markets as described above have ever switched away from the utility as the supplier of their generation services. Our target customer is not necessarily one who has switched before, rather our goal is to reach the un-switched Home CEO with a compelling offer.

UThe prices we offer customers are determined by us and are not subject to regulation.S The terms we offer are also determined by us, and we develop such to align with regulatory requirements within each state where we do business. The electricity we sell is generally ~~Electric~~metered ~~Power~~and ~~Capacity~~delivered &to ~~Generation~~our customers by local utilities. As such, ~~2014~~we do not have a maintenance or service staff for customer locations. With certain limited exceptions, these utilities also provide customer billing and collection services on our behalf, generally under the utility consolidated billing structure.

					Nameplate Capacity					Generation				Capacity
	Plants		Generators		GW		Percent			TWh	Percent			Factor (1)
By Energy Source
Coal		491		1,145		325.8		27.8	%	1,582		38.6	%		55.4	%
Petroleum		1,082		3,573		46.9		4.0	%	30		0.7	%		7.4	%
Natural gas & other gases		1,792		5,820		497.3		42.4	%	1,139		27.8	%		26.1	%
Nuclear		62		99		103.9		8.9	%	797		19.5	%		87.6	%
Other (2)		94		131		3.3		0.3	%	13		0.3	%		47.0	%
Total non-renewable		3,521		10,768		977.2		83.3	%	3,561		87.0	%		41.6	%
Hydroelectric		1,482		4,185		100.4		8.6	%	253		6.2	%		28.8	%
Wind				1,032		65.3		5.6	%	182		4.4	%		31.8	%
Biomass		1,192		2,317		15.5		1.3	%	64		1.6	%		47.2	%
Geothermal				194		3.8		0.3	%	16		0.4	%		48.2	%
Sola				1,249		10.4		0.9	%	18		0.4	%		19.3	%
Total renewable		2,674		8,977		195.4		16.7	%	532		13.0	%		31.1	%
Total, all sources		6,195		19,745		1,172.6		100.0	%	4,094		100.0	%		39.9	%
By Producer Type
Electric utilities		3,118		9,510		675.7		57.6	%	2,382		58.2	%		40.3	%
Non-CHP IPPs		3,189		6,975		423.8		36.1	%	1,555		38.0	%		41.9	%
CHP IPPs		247		559		37.9		3.2	%	—		0.0	%		0.0	%
Commercial (3)		649		1,085		4.1		0.4	%	13		0.3	%		34.7	%
Industrial (3)		474		1,616		31.1		2.7	%	144		3.5	%		52.9	%
Total, all producers (4)		7,677		19,745		1,172.6		100.0	%	4,094		100.0	%		39.9	%
Disposition of Generation
Total, all sources										4,094		108.7	%
Line losses, plant, and direct use, net										(329)		-8.7	%
Retail sales to ultimate consumers										3,765		100.0	%

Although our marketing efforts just began in the first quarter of 2016, we plan to reach residential prospects utilizing offline and online marketing channels. The offline channel includes vehicles such as outbound telemarketing, door-to-door, and direct mail. The online channel includes paid search, display ads, retargeting ads, affiliate, email, state-run comparison-shopping engines, and the like. Our goal is to invest an optimal amount in new customer acquisition, and focus on customer retention and the lifetime value inherent in satisfied customer relationships.

~~Source:~~To ~~EIA~~date, ~~Electric~~most ~~Power~~of ~~Annual~~our ~~with~~customers ~~data~~have ~~for~~come ~~2014,~~from ~~released~~the ~~February~~outbound ~~2016,~~telemarketing ~~next~~and ~~release~~door-to-door ~~February~~channels. We are also re-designing our web site and in the first half of 2017, we expect to begin testing online paid search and direct mail.

~~Notes~~The table below summarizes certain areas of our intended marketing and brand-building strategies:

1 - The capacity factor is a measure of how often a generator runs and compares how much electricity it actually produces with the maximum it could produce during a specific period of time. For example, if a 1 MW generator produced 5,000 MWh over a year, its capacity factor would be 57%, because 5,000 MWh is 57% of the electricity it could have produced if it operated all 8,760 hours in the year at full capacity. Generators with relatively low fuel costs are usually operated to supply base load power, and typically have average annual capacity factors of 70% or more. Generators with lower capacity factors may indicate that they are operated during peak demand periods or have high fuel costs, or their operation depends on the availability of the energy source, such as hydro, solar, and wind energy.

Target Consumer		The Home CEO Each household has someone in charge of managing all the activities related to their home. While the role may be shared, it is largely a thankless task but still an important job that needs to be handled. Ideally, we will reach un-switched Home CEO’s.

Relevant Insights		Fear of making a regrettable decision The Home CEO is bombarded with life-related events that have resulted in an overall stress level that makes them “fear making a bad decision,” such that they avoid making any decision. We believe this has contributed significantly to many potential customers NOT making an energy choice.

Key Selling Point		Aspirity simplifies choice This statement is what makes Aspirity better than the competition. We will use this simple, single-minded benefit to motivate customers to choose us over their current provider or other potential options.

Value Proposition		Aspirity turns the chaos of data into actionable information The ability to turn a chaos of data into useful information will take customers from a place of stress to one of calm. As a result, the fear of making decisions they may regret will diminish.

Point of Differentiation		Aspirity organizes complex issues simply Our 4-step approach turns information into knowledge:

2 ● Un-confuse ~~Other~~– ~~non-renewable~~People ~~sources~~cannot ofbegin ~~energy~~to ~~include~~learn ~~batteries,~~something ~~chemicals,~~new ~~hydrogen,~~if ~~pitch,~~they ~~purchased~~are ~~steam,~~confused. ~~sulfur~~● Organize – Eliminate irrelevant information, ~~tire-derived~~then ~~fuels~~ organize the remainder. ● Compare – Provide opportunities to test the impact of different factors; our goal is to help customers make their choice. ● Choose – Making knowledgeable choices make one feel confident and ~~miscellaneous~~minimizes ~~technologies~~fear.

3 - The industrial sector includes only independent power producers’ CHP facilities while the commercial sector Includes a small number of electricity-only, non-combined heat and power plants.

4 - Excludes distributed and dispersed generators and net metering customers. Distributed and dispersed generators are commercial and industrial generators that are, respectively, connected and un-connected to the grid. Both types may be installed at or near a customer’s site or at other locations and may be owned by either by customers or the distribution utility. Net metering is a service under which electricity generated by a consumer from an eligible facility and delivered to the utility may be used to offset energy provided by the utility during the applicable billing period.

~~U.S. Electric~~Reason ~~Power~~to ~~Industry~~Believe ~~Revenue,~~Aspirity ~~Unit~~is ~~Sales,~~significantly ~~Customers,~~different ~~and~~than ~~Average~~the ~~Retail~~competition ~~Prices,~~Until ~~All~~our ~~Sectors~~brand is more widely known, ~~2014~~we will need to do two things to support the decision to choose Aspirity:

	Entities (count)		Revenues ($millions)		% of Total			Unit Sales (TWh)		% of Total			Customers (000s)		% of Total			Avg Retail Price (¢/kWh)
By Energy Provider
Investor-owned utilities		208		228,353		58.1	%		1,935		51.4	%		86,838		58.9	%		11.80
Retail energy providers		652		57,019		14.5	%		743		19.7	%		20,070		13.6	%		7.67
Non-utility power producers		213		974		0.2	%		16		0.4	%		1		0.0	%		5.93
Behind the meter		94		228		0.1	%		2		0.0	%		167		0.1	%		12.92
Subtotal		1,167		286,574		72.9	%		2,696		71.6	%		107,076		72.7	%		10.63
Cooperatives		859		44,624		11.4	%		429		11.4	%		18,947		12.9	%		10.39
Municipally-owned utilities		827		39,898		10.1	%		395		10.5	%		15,008		10.2	%		10.09
Public power districts		81		9,640		2.5	%		109		2.9	%		3,861		2.6	%		8.83
State-owned utilities		11		5,807		1.5	%		52		1.4	%		1,340		0.9	%		11.21
Federally-owned utilities		26		1,295		0.3	%		32		0.8	%		35		0.0	%		4.11
Subtotal		945		56,640		14.4	%		588		15.6	%		20,245		13.7	%		9.64
Adjustments (1)		69		5,258		1.3	%		51		1.4	%		1,106		0.8	%		10.28
Total U.S.		3,040		393,096		100.0	%		3,765		100.0	%		147,374		100.0	%		10.44
By Choice Type (2)
Type 0		2,292		222,213		56.5	%		2,312		61.4	%		81,657		55.4	%		9.61
Type 1		679		112,947		28.7	%		987		26.2	%		42,589		28.9	%		11.44
Type 2		25		35,457		9.0	%		249		6.6	%		13,590		9.2	%		14.26
Type 3		21		14,248		3.6	%		129		3.4	%		5,839		4.0	%		11.06
Type 4		23		8,231		2.1	%		87		2.3	%		3,699		2.5	%		9.41
Subtotal		748		170,883		43.5	%		1,452		38.6	%		65,717		44.6	%		11.77
Total U.S.		3,040		393,096		100.0	%		3,765		100.0	%		147,374		100.0	%		10.44
By Census Region (3)
New England		266		18,557		4.7	%		120		3.2	%		7,133		4.8	%		15.45
Middle Atlantic		323		49,331		12.5	%		368		9.8	%		18,099		12.3	%		13.41
South Atlantic		422		81,153		20.6	%		572		15.2	%		30,246		20.5	%		14.19
East North Central		423		56,337		14.3	%		301		8.0	%		22,215		15.1	%		18.71
East South Central		246		28,973		7.4	%		806		21.4	%		9,517		6.5	%		3.60
West North Central		514		27,477		7.0	%		319		8.5	%		10,730		7.3	%		8.61
West South Central		300		50,925		13.0	%		589		15.6	%		17,587		11.9	%		8.65
Mountain		267		25,651		6.5	%		272		7.2	%		10,728		7.3	%		9.42
Pacific - contiguous		241		50,445		12.8	%		402		10.7	%		20,299		13.8	%		12.55
Pacific - noncontiguous		38		4,248		1.1	%		16		0.4	%		820		0.6	%		27.14
Total US		3,040		393,096		100.0	%		3,765		100.0	%		147,374		100.0	%		10.44

	●	The user experience must be simple and intuitive – Our brand promises of Advocacy, Clarity, Information, Anticipation, Customization, and Transparency must be clear.

	●	We will not be confusing or misleading – In contrast to the competition, we will avoid behaviors that don’t put customers first.

~~Source: Company~~Brand ~~analysis~~Character ofWe Userve our customers and always put them first Our customers must always feel that we put them first and are fully empathetic to their needs.S. ~~EIA~~We ~~Form~~will ~~861~~use ~~data~~humility, ~~released~~enthusiasm, ~~February~~and ~~2016,~~intelligence ~~next~~to ~~release~~consistently ~~October~~anticipate ~~2016~~customer needs. Desired Consumer Response Aspirity helps me make great decisions We will earn our customers respect and they will reward us with their loyalty and sincere testimonials like:

~~Notes~~● “Prior to Aspirity, decisions about my home were confusing, time-consuming, and very stressful to work through”. ● “Aspirity simplifies complex problems into relevant learnings, clear trade-offs, and personalized plans to fit my needs”.

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

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

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

The investor-owned portion of the industry, including utilities, retail energy providers, and non-utility generators, and constitutes over 70% of the industry’s revenues, unit sales, and customers as shown by the table above. According to the Edison Electric Institute, a trade group representing the largest investor-owned utilities, in 2014, total energy operating revenues of shareholder-owned electric companies were $377 billion[6]. As of December 31, 2014, consolidated holding company-level assets of these entities were $1.378 trillion, and of these assets, $833 billion were net property in service. In 2014, shareholder-owned electric utilities spent $19.5 billion on transmission investment, compared to $16.9 billion in 2013, are projected to spend $20.7 billion in 2015, and are planning to invest approximately $85 billion in transmission construction between 2015 and 2018. The total market capitalization of U.S. shareholder-owned electric companies was $632 billion on December 31, 2014.

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.

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

However, in a state with a restructured or “deregulated” market, that is, the “restructured retail” business or one with retail choice, the generation, transmission, distribution, and retail marketing functions of the business are legally separated and pricing of energy is unbundled from delivery services. In 2014, according to EIA data, all customer types eligible to choose bought over 563 GWh from competitive suppliers, up 0.8% from 559 GWh in 2013.

6 Note that this figure also includes revenues from the sale of natural gas.

U.S. Electric Power Industry Revenue, Unit Sales, Customers, and Average Retail Prices, 2014

	Revenues ($millions)		% of Total			Unit Sales (TWh)		% of Total			Customers (000s)		% of Total			Avg Retail Price (¢/kWh)
By Customer Type
Residential		176,178		44.8	%		1,407		37.4	%		128,680		87.3	%		12.52
Commercial		145,253		37.0	%		1,352		35.9	%		17,854		12.1	%		10.74
Industrial & other		71,665		18.2	%		1,005		26.7	%		839		0.6	%		7.13
Total industry		393,096		100.0	%		3,765		100.0	%		147,374		100.0	%		10.44
Residential		160,637		40.9	%		1,301		34.6	%		117,231		79.5	%		12.34
Commercial		113,880		29.0	%		1,084		28.8	%		15,942		10.8	%		10.51
Industrial & other		57,328		14.6	%		816		21.7	%		790		0.5	%		7.03
Full service providers		331,845		84.4	%		3,201		85.0	%		133,963		90.9	%		10.37
Residential		15,541		4.0	%		106		2.8	%		11,450		7.8	%		14.70
Commercial		31,373		8.0	%		268		7.1	%		1,912		1.3	%		11.69
Industrial & other		14,338		3.6	%		189		5.0	%		49		0.0	%		7.57
Restructured retail		61,251		15.6	%		563		15.0	%		13,411		9.1	%		10.87
Residential		9,079		2.3	%		—		—			—		—			8.59
Commercial		19,948		5.1	%		—		—			—		—			7.43
Industrial & other		11,250		2.9	%		—		—			—		—			5.94
Energy only providers		40,277		10.2	%		—		—			—		—			7.15
Residential		6,462		1.6	%		—		—			—		—			6.11
Commercial		11,425		2.9	%		—		—			—		—			4.26
Industrial & other		3,088		0.8	%		—		—			—		—			1.63
Delivery service only		20,975		5.3	%		—		—			—		—			3.72

Source: Company analysis of U.S. EIA Form 861 data for 2014, re-released February 19, 2016, next release October 2016.

Wholesale Electricity Markets

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

Wholesale electricity prices are driven by supply and demand and actually change minute-by-minute. Near term demand is largely affected by the weather and consumer behavior while supply is driven by plant availability and fuel prices, particularly for natural gas as it is the fuel of choice for marginal generation requirements.

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

After PURPA, the Energy Policy Act of 1992 was the next major legislative step towards full deregulation of wholesale power markets and in 1996, FERC issued Orders 888 and 889, which led to the creation of the network of “OASIS” or Open Access Same-Time Information System nodes, which allowed for energy to be scheduled across multiple power systems. In December 1999, FERC issued Order 2000 calling for electric utilities to form RTOs or ISOs to operate the nation’s bulk power system with the intended benefits of eliminating discriminatory access to transmission for all generators, improving operating efficiency, and increasing system reliability. ISOs are typically not-for-profit entities, use governance models developed by FERC, and operate under its regulatory authority.

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

In general, wholesale market activity is characterized by the acquisition of electricity at a given location such as a node or hub and its delivery to another. Short-term 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. ISOs may also offer longer term financial contracts known as FTRs. Physical transactions are settled by the delivery of the commodity. 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 exchanges regulated by the CFTC, 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.

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

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

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

Restructured Retail Electricity Markets

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

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

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

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

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

Today, years after Massachusetts and Rhode Island became the first states to effectively implement choice in 1998, 20 jurisdictions have some form of choice[7]. We define these forms of retail choice as follows:

Type 1	All residential, commercial, and industrial customers served by investor-owned utilities may choose their energy provider;
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.

7 Generally,only customers of investor-owned utilities are eligible to choose their electric supplier while those served by a municipal, cooperative, or other type of non-investor owned utility are ineligible. However, there are certain areas where customers of specific cooperatives and public utilities may have choice but these instances are rare.

Some states require that utilities billing customers in their service territory on behalf of a retailer purchase the receivables generated as a result of energy sales. These states are known as “purchase of receivables” or “POR” jurisdictions. The purchase generally occurs at a modest discount of 0% to 2.5% to reflect bad debt experience by customer class within the service territory.

In POR areas, retailers have no customer credit exposure other than the bad debt charge because the utility pays regardless of whether or not the customer does. However, if a customer fails to pay, the utility will typically disconnect service, which results in the loss of the account for the retailer. In areas with without POR programs - non-POR areas - retailers are exposed to the credit risk of the customer. New Jersey is currently the only “recourse POR” state. Under these rules, retailers have no exposure to customer credit risk provided that the customer is billed under a utility’s consolidated billing program. However, if an electric account is in default for 90 days (about 120 days from the last invoice date), the utility has the option to convert the customer to dual billing.

POR laws have the effect of converting the retailer’s exposure to its customers’ credit to that of the applicable utility, which is generally “investment grade” under the scales of the Nationally Recognized Statistical Rating Organizations recognized by the SEC, such as Standard & Poor’s. A “BBB-” by S&P is considered to be the lowest investment grade by market participants.

The Type 1 retail choice jurisdictions incorporate 54 investor-owned utility service territories. In addition to obtaining licenses from appropriate state regulatory authorities, in order to supply power to customers within a given LDC service area, a retailer must become “EDI compliant” with that utility, which allows for access to their billing systems. In general, there are three billing structures available to competitive suppliers in restructured markets:

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

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

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

In the 14 areas where all rate classes had choice during 2014, according to the ABACCUS 2015 study supplemented by Company research, just over 38.0 million residential customers were eligible to choose their supplier. Of these totals, over 23.5 million or just under 62% had not switched away from the incumbent utility. 14.3 million or about 38% (in a range from 0.1% to 80.7%) had switched at least once.

For the Type 1 retail choice markets, the table below summarizes the POR status, number and credit of investor-owned utilities, the number of eligible residential customers, and recent prices:

Type 1 Retail Choice Residential Markets Overview

	Utilities				Customers							Prices (¢/ kWh, 1)
				Avg					Switch			2014						2015		2015
	POR			Credit					Rate			Energy		Delivery		Avg		Avg		vs
State	Status	IO Us		Rating	Eligible		Unswitched		(2,3)			Only		Only		Price		Price		2014
CT	full		2	A-		1,401,000		916,000		34.6	%		11.79		8.03		19.82		20.95		5.7	%
DE	none		1	BBB+		273,000		245,000		10.3	%		10.12		2.69		12.81		13.09		2.2	%
DC	in proces:		1	BBB+		243,000		209,000		14.0	%		10.06		3.35		13.41		13.61		1.5	%
IL	full		4	BBB+		4,604,000		1,780,000		61.3	%		6.77		5.23		12.00		12.58		4.8	%
ME	none		2	BBB+		767,000		595,000		22.4	%		7.41		10.00		17.41		19.80		13.7	%
MD	full		4	BBB		2,028,000		1,543,000		23.9	%		10.15		3.52		13.67		14.04		2.7	%
MA	full		4	A-		3,347,000		2,749,000		17.9	%		10.71		4.60		15.31		15.66		2.2	%
NH	none		3	BBB+		522,000		377,000		27.8	%		9.60		7.99		17.59		18.50		5.2	%
NJ	recourse		4	BBB+		3,377,000		2,913,000		13.7	%		13.06		2.67		15.73		15.89		1.0	%
NY	full		6	BBB+		5,811,000		4,486,000		22.8	%		12.02		8.04		20.06		18.54		-7.6	%
	full		1	BBB-		618,000		316,000		48.9	%
OH	in process:		1	BBB-		1,274,000		885,000		30.5	%		6.51		6.08		12.59		12.69		0.8	%
	none		4	BBB-		2,303,000		740,000		67.9	%
PA	full		10	BBB		4,985,000		3,187,000		36.1	%		9.13		4.22		13.35		13.92		4.3	%
RI	none		1	BBB+		493,000		457,000		7.3	%		10.39		6.84		17.23		19.35		12.3	%
TX	none		6	BBB+		5,986,000		2,144,000		64.2	%		—		—		11.86		11.66		-1.7	%
Sum/avg			54	BBB+		38,032,000		20,542,000		08.1	%		0.82		5.64		15.20		15.73		3.5	%
	full		31	BBB+		22,794,000		14,977,000		34.3	%
	recourse		4	BBB+		3,377,000		2,913,000		13.7	%
	in process:		2	BBB+		1,517,000		1,094,000		27.9	%
	none		17	BBB		10,344,000		4,558,000		55.9	%
Sum/avg			54	BBB+		38,032,000		20,542,000		08.1	%

Sources

ABACCUS 2015; EIA Electric Power Annual 2014; EEI website accessed March 4, 2015; Company analysis of company websites.

Notes

1	“Energy Only” providers sell energy to customers and incumbent utilities provide “Delivery Only” services for these customers. In Texas, customers served by REPs must be provided with bundled energy and delivery services.
2	“Switch rate” refers to the percentage of customers that have migrated away from the incumbent provider’s default service product (the standard offer, basic service, generation service, etc.).
3	In Texas’ competitive markets (ERCOT), all eligible residential customers take competitive electric service and the switch rate indicates the number not served by the incumbent retail energy provider. Total eligible customers refer to those within ERCOT, or about 60% of the 9,954,000 residential accounts in the state.

Overall, we believe that choice is proving to be a boon for consumers with respect to providing them with the ability to manage their electricity costs. According to an analysis of data from the EIA, between 2002 and 2014, retail rates for all customer sectors in states with restructured retail markets increased by 47.2% compared with a 39.5% increase in states that rely on regulated utilities. However, as shown by the chart below, unbundled prices in all Type 1 areas since 2011 have been consistently lower that the bundled service offered by the incumbent utilities.

Unbundling of electric bills in restructured markets made many aware for the first time exactly what they were paying for. In general, the bills of retail electricity customers include numerous costs and charges that can be classified into energy costs, delivery charges, and governmental policy costs. These include the costs of federal and state polices with respect to electricity and may include transition charges or costs associated with moving from a regulated market to a restructured one, allowing EDCs to recapture stranded costs that would otherwise be unrecoverable after deregulation, societal benefits charges such as the costs of mandated programs such as universal service, lifeline service, and energy efficiency programs, and sales and use taxes collected by state and local authorities on retail electricity sales.

According to analysis of EIA data for states with restructured markets, on average between 2002 and 2014 (the latest year for which information is available) energy and delivery costs accounted for about 67% and 33%, respectively, of the average retail electricity price. Of course, these percentages fluctuate from year to year and state to state, primarily due to wholesale energy market conditions, weather, and state rules.

Sales & Marketing

As of March 30, 2016, we are licensed in five full choice jurisdictions and are EDI compliant with three utilities serving a total of 4.5 million residential accounts. As of the same date, we have 1,587 confirmed customers. By the end of 2016, we plan on being licensed in all 14 Type 1 jurisdictions and EDI compliant with 50 IOUs serving about 38 million residential customers as shown by the table below:

Aspirity Energy Expected Market Rollout Plan

Last updated March 23, 2016

	ISOs		States		EDI Ready IOU Service Areas		Accessable Customers (000s)
Period	Inc	EoP	Inc	EoP	Inc	EoP	Inc	EoP
2015	1	1	3	3	1	1	618	618
Jan 2016	-	1	-	3	1	2	3,463	4,081
Feb 2016	-	1	1	4	1	3	455	4,536
Mar 2016	-	1	3	7	-	3	-	4,536
Q1 2016	-		4		2		3,918
Apr 2016	1	2	-	7	6	9	5,566	10,102
May 2016	2	4	1	8	-	9	-	10,102
Jun 2016	1	5	2	10	12	21	6,214	16,316
Q2 2016	4		3		18		11,780
Jul 2016	-	5	4	14	2	23	-	16,316
Aug 2016	-	5	-	14	5	28	11,770	28,086
Sep 2016	-	5	-	14	9	37	2,897	30,983
Q3 2016	-		4		16		14,667
Oct 2016	-	5	-	14	1	38	7,011	37,994
Nov 2016	-	5	-	14	12	50	-	37,994
Dec 2016	-	5	-	14	-	50	-	37,994
Q4 2016	-		-		13		7,011
2016	5		14		50		37,994

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

The prices we offer customers are determined by us and are not subject to regulation. The terms we offer are also determined by us, and we develop such to align with regulatory requirements within each state where we do business. The electricity we sell is generally metered and delivered to our customers by local utilities. As such, we do not have a maintenance or service staff for customer locations. These utilities also provide billing and collection services for the majority of our customers on our behalf, generally under the utility consolidated billing structure.

Although our marketing efforts just began in the first quarter of 2016, we plan to reach residential prospects utilizing offline and online marketing channels. The offline channel includes vehicles such as outbound telemarketing, door-to-door, direct mail, events, brokers, out-of-home, etc. The online channel includes paid search, display ads, retargeting ads, affiliate, email, state-run comparison-shopping engines, etc. Our goal is to invest an optimal amount in new customer acquisition, and focus on customer retention and the lifetime value inherent in satisfied customer relationships.

Energy Supply

The retail energy business involves the purchase of electricity in wholesale markets and the virtually simultaneous resale of such to retail customers. In general, ISOs require payment for energy purchased on a weekly or twice-weekly basis. In some markets, retailers are also required to buy capacity and certain ancillary services onand apay ~~monthly~~for ~~basis~~it every month. In all cases, retailers are required to provide market operators with “financial assurance” oralso “known as collateral”, typically in the form of cash or a letter of credit in an amount equal to 60 to 75 days’ worth of such purchases. However, retailers typically only receive payment from customers on once a ~~monthly basis~~month. Consequently, a substantial amount of liquidity and capital may be required to both satisfy payables and carry receivables. We do not own any generation, transmission, or distribution facilities and utilize wholesale suppliers for our supply requirements and utilities for our transmission and distribution needs.

On March 30, 2016, we entered into a full requirements preferred supply agreement with Exelon ~~Generation Company, LLC, a Pennsylvania limited liability company and wholly-owned subsidiary of Exelon Corporation (“Exelon”),~~ to provide us with all the power and ancillary services we need to serve our customers for an initial term expiring on March 30, 2019 ~~(the “PSA”)~~. As of December 31, ~~2015~~2016, Exelon was the operator of the second largest generation fleet in the U.S. and its long-term S&P credit rating was BBB.

Under the terms of the PSA, on a daily or weekly basis as we request, Exelon ~~will~~provides ~~provide~~us with firm, fixed price quotes for power for terms of ~~one~~ 1, 3, 6, 9, 12, 15, 18, 24, ~~27,~~ 30, and 36 months out for each of the service areas in which we operate. ~~Such~~Exelon’s ~~quotes~~prices to ~~will~~us include all costs of energy, capacity, and ancillary services necessary to serve residential and small commercial customers. We may also meet state minimum “green” or renewable energy supply criteria by acquiring renewable energy certificates or RECs from Exelon via the PSA. If necessary, we may also buy additional RECs to satisfy the requirements of customers selecting a product with a percentage of ~~green~~renewable power higher than state minimums. We then mark up these costs to obtain selling prices. In addition, under the PSA, Exelon absorbs all volumetric risk or deviations between forecasted and actual customer usage. Finally, the PSA provides that Exelon will post any collateral required of us by an ISO or EDC.

Exelon ~~will~~invoices ~~invoice~~ us for all purchases under the agreement every month. The PSA also incorporates the ability for us to defer payment of of all or a portion of these invoices based on certain financial criteria as defined in the agreement. WeWith ~~are~~respect ~~exposed~~ to the ~~risk~~agreement, ~~that~~if Exelon ~~may~~fails ~~fail~~ to deliver. Ifor ~~this~~if ~~were~~we default and are unable to ~~occur~~cure such, we would then be forced to pledge collateral and buy the required power from either an ISO or another wholesale supplier and the costs of such may be higher or lower than those embodied in the PSA.

Credit Risk Management

In ~~connection~~the ~~with~~ordinary ~~our retail electricity business~~course, weAspirity ~~intend~~Energy toprovides ~~provide~~ trade credit to ~~our~~consumers ~~customers.~~and Wecommercial ~~are~~enterprises ~~considering implementing the policies~~ and ~~underwriting~~all ~~strategy~~states ~~presented~~with ~~below~~restructured retail toenergy ~~allow~~markets ushave toput ~~accept~~in ~~any~~place ~~business~~laws byand ~~taking~~regulations ~~deposits~~with ~~only~~respect ~~from~~to ~~the~~permitted ~~riskiest accounts.~~billing, ~~If implemented~~credit, ~~collection activity~~ and ~~cost~~collections ~~will~~practices. This beexposes ~~largely~~us ~~eliminated since if a customer fails~~ to ~~pay~~certain incredit arisks ~~timely fashion,~~which ~~then~~ we ~~will~~manage ~~simply~~in ~~cease~~different ~~providing service and apply the deposit to the outstanding bill~~ways. ~~This credit policy is summarized as follows:~~

●Some states Ifrequire athat ~~prospect~~utilities isbilling ~~located~~customers in their service territory on behalf of a retail supplier purchase the receivables from electricity sales. These areas are known as purchase of receivables or POR ~~area~~jurisdictions. These purchases by the utility from the retailer generally occur at a modest discount of 0% to 2.5% to reflect the bad debt experienced within the service territory. Consequently, wesuppliers ~~will~~have ~~accept~~no retail credit exposure other than the ~~account~~bad asdebt charge because the utility ispays regardless of whether the ~~account~~customer ~~obligor~~does. ●However, Ifif a ~~prospect~~customer isfails ~~located~~to inpay, athe ~~non-POR~~utility ~~area~~will ~~and~~typically isdisconnect aservice, ~~residential~~which results in the loss of the account, wefor ~~will~~the ~~check~~retailer. ~~their~~In ~~three~~states with retail choice but without POR programs -~~bureau~~ ~~FICO~~the ~~score:~~non-POR jurisdictions - retailers are exposed to the credit risk of the customer.

	●	If the score is above a certain threshold, we will accept the account without a deposit.
POR Programs in Full Retail Choice Jurisdictions
	●	If the score is below the threshold, we will accept the account with a deposit equal to the dollar value of 90 days of expected energy sales.
Type		Count		States
Full			6	CT, IL, MA, MD, NY, PA
Recourse			1	NJ
Limited area			1	OH
In progress			1	DC
None			5	DE, ME, NH, RI, TX
Total			14	--

25POR laws have the effect of converting a retailer’s exposure to its customers’ credit to that of the applicable utility, the vast majority of which are rated as “investment grade” on the scales of the Nationally Recognized Statistical Rating Organizations recognized by the SEC. Consequently, if a prospect is in a POR area, we will accept the account as the utility is the account obligor and we have very limited exposure to credit loss.

●For non-POR Ifareas, awe ~~prospect~~believe isthe ~~located~~underwriting instrategy asummarized ~~non-POR~~below, ~~area~~which we expect to implement during 2017, allows us to prudently accept business by taking deposits only from the riskiest accounts. Collection activity and cost is largely eliminated since if a ~~non-residential~~customer ~~account~~fails to pay in a timely fashion, then we will ~~check~~simply ~~their~~cease ~~trade~~providing ~~credit~~service ~~score~~and apply the deposit to the outstanding bill, specifically:

●	●For residential service, we will check the consumer credit score of the primary obligor on the account and for non-residential service, we will check the trade credit score of the business in question:	~~If the score is above the threshold level, we will accept the account without a deposit.~~
	●	If the score is below the threshold, we will accept the account with a deposit equal to the dollar value of 90 days of expected energy sales.
	○	If the scores are above our cutoffs, we will accept the account without a deposit.
	○	If the scores are below our thresholds, we will accept the account with a deposit equal to a portion of our expected annual revenue.
●	To size deposits, we will estimate the next 12 months of revenue based on expected usage, our power price for the area, and a 90-day delinquency threshold.
●	After 12 prompt payments on their account, the customer may elect to either have their deposit returned to them or applied to their account.

● To size any deposits required, we will estimate or check the account’s last 12 months of historical energy usage and the most recent average forecast wholesale energy price for the area for the next 12 months. Our general deposit sizing formula is as follows: Deposit = annual kWh usage x average energy price/kWh ÷ 100 x deposit factor of 25%. ● After a year of prompt payments on their account, the customer may elect to either have their deposit returned to them or applied to their account. ● If no payment has been received on an account for 60 days after an invoice date, a second invoice is sent, and if within 30 days of the date thereof:Financial Services

~~● Full payment is received~~To date, ~~then~~our itprimary isfocus ~~applied~~has tobeen ~~the~~on ~~balance~~building ~~due~~our ~~and~~retail ~~the~~energy ~~account is returned to good standing~~business. ●For ~~Partial payment is received, then it is applied to~~ the ~~balance~~near ~~due and 15 days later~~term, aour ~~new~~financial ~~invoice~~services business is expected ~~sent~~to ~~requesting~~consist ~~payment~~primarily of ~~the~~our ~~new~~lending ~~balance.~~relationships ●with IfEnterprises, aour ~~security~~first ~~deposit~~financial ~~has~~services ~~been~~customer. ~~taken~~Ultimately, we ~~and~~intend ~~payment~~to isinvest ~~not~~in ~~received,~~other ~~then~~commercial ~~the~~loans ~~account~~to isbusinesses ~~closed~~operating ~~and~~in the ~~security~~energy ~~deposit~~industry ~~applied. ● If a security deposit has not been taken~~ and ~~payment~~we isalso ~~not~~may ~~received,~~make ~~the~~loans ~~account is sent~~ to aindividuals and ~~collection agency:~~households.

	●	If the agency’s collection effort is successful, then it will notify us via email with respect to the total amount they were able to collect, followed within two weeks by a receipt and check for the amount collected, less their fee. Customer accounts are not credited until the agency’s check is received.
	●	If the collection effort is unsuccessful after 30 days, then the account balance will be written off.

Competition

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

Seasonality

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

Personnel

As of March 30, 2016, we employed 11 persons, including four executives, four marketing and operations professionals, two accountants, and one administrative professional. We also utilize the services of one independent contractor. We have entered into employment agreements with all of our employees, do not employ any unionized labor, and are engaged in extensive hiring efforts to build staff.

To attract and retain qualified personnel, we employ a competitive compensation system that incorporates a base salary and annual cash bonuses based on job position and corporate performance. Employee benefits available through, or paid by, us include medical and dental insurance, a 401(k) plan, and unlimited time off.

Regulatory Matters

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

Item 1A – Risk Factors

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

As a result of ~~the~~our recent Restructuring, and our ~~only~~startup ~~current~~businesses, ~~source~~our primary sources of cash flow isare ~~payments~~sales of Notes and payments from Enterprises on the Term Loan ~~and sales of Notes~~.

We do not expect to ~~have~~break-even ~~significant~~on ~~revenue~~a month-~~generating~~to-month ~~operations~~cash ~~until~~flow ~~the~~basis ~~middle~~until of2018 ~~2016~~ at the earliest. Prior to that, we will rely on the timely payment of the Term Loan and on our ability to sell Notes in order to fund our retail energy start-up operations and repay Notes as they are redeemed. We are relying on the ability of Enterprises to pay amounts owed to us under the Term Loan to provide us with the funds necessary to repay our indebtedness on the ~~Term Loan~~ Notes. If Enterprises fails to pay amounts owed to us when due, or if our business does not provide enough cash to cover all of our liabilities, we may be unable to pay the interest or principal payments on the Notes as they become due. Enterprises’ ability to make timely payments on the Term Loan will, at least initially, depend on the wholesale energy trading operations of Enterprises’ subsidiaries, ~~its major debtor, Angell,~~ and the operations of the other legacy businesses. Wholesale energy trading is volatile and unpredictable, and was ~~generally~~ not profitable for Enterprises in ~~2015~~2016. In the event amounts owed to us are paid late or not paid, our ability to fund operations and repay notes will be negatively impacted.

Even after we ~~begin~~break ~~generating~~even ~~revenue~~on ~~through~~ our new retail energy business, those operations alone may not produce a sufficient return on investment to pay the stated interest rates on the Notes and fund our capital needs. We may be substantially reliant upon the proceeds we receive from the sale of Notes in order to meet our liquidity needs. We may not be able to attract new investors or have sufficient borrowing capacity when we need additional funds to repay principal and interest on Notes.

We have a history of operating losses and we may not become profitable in the future, which could ultimately result in our inability to continue operations in the normal course of business.

For the year ended December 31, 2016, on a consolidated basis, the Company reported a net loss from continuing operations of $12,893,000 and cash used for continuing operations of $11,064,000. On the same basis, for the year ended December 31, 2015, we recorded a net loss from continuing operations of $8,862,000 and cash used for continuing operations of $5,884,000.

As of December 31, 2016, the Company had unrestricted cash, negative working capital, and total members’ deficit of $1,300,000, $14,338,000, and $31,298,000, respectively.

There is no assurance that our operating activities will be able to fund our cash requirements in the future, which could ultimately result in our inability to continue operations as a going concern.

Historical losses and upcoming debt maturities have raised concerns about our ability to continue operations at the current level.

Historically, the Company has relied on sales of Notes and payments from its Term Loan to Enterprises as its principal sources of funding and will continue to do so for at least the next 12 months until it can generate sufficient operating cash flow to fund its ongoing business. As of December 31, 2016, $12,430,000 of Notes will mature prior to December 31, 2017. Historically, a significant portion of maturing Notes renew, which does not require a cash outlay by the Company. However, the decision to redeem or renew is solely at the discretion of the noteholder and not the Company.

While the Company expects that Notes will be redeemed at rates similar to those that have occurred historically, management’s analysis of the ability of the Company to continue as a going concern must consider the possibility that all Notes maturing for at least the next 12 months from the issuance of the financial statements will be redeemed. If such events were to occur, the Company would not have enough liquidity to meet all redemption requests, given the Company currently has no other sources of capital that could be accessed to cover increased redemptions from these Notes.

To evaluate the Company’s ability to continue as a going concern, the Company considered both the aggregation of the negative financial metrics, as noted above, and the possibility these will not turn positive for at least the next 12 months. Further, the Company assessed the possibility of the redemption of all Notes maturing in the next 12 months by the respective noteholders. These uncertainties suggest there is substantial doubt as to the Company’s ability to continue as a going concern within one year from the date that these financial statements were issued.

Management has plans intended to mitigate the conditions described above. These plans include growing customer acquisitions such that positive operating cash flow is generated on a sustained basis beginning in the first half of 2018, continuing collection on the Term Loan, and continuing to sell Notes. Further, the Company intends to evaluate other sources of debt and equity financing, there can be no assurance that these efforts will be successful

While the Company believes that payments from Enterprises on the Term Loan, anticipated cash generated from operating activities, availability of trade credit, and anticipated proceeds from the Notes Offering will be sufficient to meet operating cash requirements and Note redemption obligations for the next twelve months, the Company is unable to conclude that it is probable that management’s plans will fully mitigate the conditions identified.

Our consolidated financial statements reflect the financial condition and results of operation of Enterprises.

~~Following~~After the ~~Distribution~~spinoff ~~and~~of ~~until~~Enterprises aon ~~reconsideration~~November ~~event as defined under GAAP occurs~~1, we2015 ~~must~~but ~~consolidate~~prior ~~Enterprises~~to asMarch a30, ~~variable interest entity or “VIE”. Consequently~~2016, ~~our consolidated financial statements include~~ the financial ~~condition and~~ results of ~~operations of~~ Enterprises ~~even~~were ~~though we do not have access to its assets except pursuant to our contractual rights~~consolidated ~~and obligations~~ with ~~respect~~those toof the ~~Term~~Company ~~Loan.~~as ~~Enterprises is not~~ a ~~guarantor~~variable ofinterest ~~the~~entity ~~Notes.~~or ~~Investors should consider our financial condition in light of these facts and look only to the assets and expected operations of Aspirity in determining whether to invest~~VIE. ~~See “Critical Accounting Policies - Variable Interest Entities - Principles of Consolidation”.~~

AsOn aMarch ~~result~~18, of2016, ~~the~~FERC ~~Distribution,~~approved wethe ~~are~~change in acontrol ~~start~~of the Company per Docket No. EC16-up60-000. ~~phase~~This allowed the Company to adopt an amended and ~~before~~re-stated weOperating ~~can~~Agreement ~~begin~~which ~~marketing~~converted ~~our~~outstanding ~~retail~~Class ~~energy~~B ~~services~~units (certain financial rights only) to ~~customers~~Class A units (full financial and ~~generating~~governance ~~revenue~~rights) on March 30, we2016. ~~must~~This ~~apply~~constituted ~~for,~~a reconsideration event and ~~receive~~as such, a reassessment of the ~~necessary~~VIE ~~licenses~~relationship ~~and~~between ~~enter~~the ~~into~~Company ~~information~~and ~~exchange~~Enterprises and ~~billing arrangements~~the ~~with~~consolidation ~~utilities~~decision was performed as of this date.

WeWhile ~~intend~~Enterprises tois ~~develop~~still ~~and~~a ~~operate~~VIE ~~retail~~due ~~energy~~to ~~businesses~~lack inof ~~all~~sufficient 14equity ~~jurisdictions~~investment ~~that~~to ~~allow~~finance ~~all~~its ~~retail~~activities ~~customers~~without ofadditional ~~investor-owned~~subordinated ~~utilities~~financial tosupport ~~choose their electricity supplier. To do so, we require licenses from public utility commissions~~ and ~~other~~Aspirity ~~regulatory organizations.~~continues ~~These agencies impose various requirements~~ to ~~obtain~~hold ora ~~maintain~~variable ~~licenses.~~interest ~~Further,~~in ~~certain non-governmental organizations have been focusing on~~ the ~~retail~~form ~~energy~~of ~~industry and~~ the ~~treatment~~Term ofLoan, ~~customers~~for byAspirity ~~certain~~to ofconsolidate Enterprises, ~~our~~it ~~competitors.~~must ~~Any~~be ~~negative~~either ~~publicity regarding~~ the ~~industry~~primary inbeneficiary ~~general~~of, ~~and~~or ushold ina ~~particular~~controlling ~~could~~financial ~~negatively~~interest, ~~affect~~either ~~our~~by ~~relationship~~contract ~~with~~or ~~various commissions and regulatory~~via ~~agencies~~related ~~and~~party ~~could~~considerations. ~~negatively~~After ~~impact~~March ~~our~~30, ~~ability~~2016, toAspirity ~~obtain~~meets ~~new~~neither ~~licenses~~of tothese ~~expand operations or maintain the licenses currently held~~requirements. ~~Furthermore~~Specifically, weTimothy ~~must~~Krieger as ~~also~~an ~~establish~~individual ~~electronic~~is ~~connections (“EDI compliance”) with~~ the ~~utilities~~primary ~~serving~~beneficiary ~~particular areas~~of inEnterprises ~~such~~as ~~states~~he inmeets ~~which~~both wethe ~~wish~~power ~~to market our services in order to exchange customer usage~~ and ~~billing~~losses/benefits ~~information~~criteria.

27With the spinoff, we exited all wholesale trading and diversified investment activity and have no plans to engage in such in the future, therefore these operations are reported in our 2016 SEC filings and GAAP financials as discontinued operations. However, although we no longer owned REH, GAAP required that we report its business as a continuing operation through March 30, 2016 since it was not considered to be a “strategic shift” from future operations.

Although we expect most of these pre-market processes and procedures to be completed by the end of 2016, there can be no assurance that we will be able to achieve all of the arrangements we seek on a timely basis or at all or at an acceptable cost. Consequently, we may not be able to offer service in all of our target markets and failure to do so will adversely affect our ability to grow our business. Loss of licenses or failure to maintain EDI compliance could cause a negative impact on our results of operations, financial condition, and cash flow.17

Historically, these three segments of Enterprises’ business – wholesale trading, REH, and diversified investments - constituted significant parts of our operations, and therefore, our current and future financial statements are and will be significantly different from those issued prior to March 31, 2016.

Consequently, some of our consolidated financial statements include the financial condition and results of operations of Enterprises even though we do not have access to its assets except pursuant to our contractual rights and obligations with respect to the Term Loan. Enterprises is not a guarantor of the Notes.

Investors should consider our financial condition in light of these facts and look only to the assets and expected operations of Aspirity in determining whether to invest. See “Critical Accounting Policies - Variable Interest Entities - Principles of Consolidation”.

As a result of the Distribution, we are in a start-up phase and must apply for, and receive, the necessary licenses from appropriate regulatory authorities and enter into information exchange and billing arrangements with utilities.

We intend to develop and operate retail energy businesses in all 14 jurisdictions that allow all retail customers of investor-owned utilities to choose their electricity supplier and as of December 31, 2016, we held market-based rate authority from FERC, were members of the ISO-NE and PJM wholesale electricity markets, were licensed to serve retail customers in Illinois, Maryland, New York, Ohio, Pennsylvania, and Rhode Island, and had established electronic connections with 9 IOUs serving over 10 million residential accounts.

To do so, we require licenses from public utility commissions and other regulatory organizations. These agencies impose various requirements to obtain or maintain licenses. Further, certain non-governmental organizations have been focusing on the retail energy industry and the treatment of customers by certain of our competitors. Any negative publicity regarding the industry in general and us in particular could negatively affect our relationship with various commissions and regulatory agencies and could negatively impact our ability to obtain new licenses to expand operations or maintain the licenses currently held. Furthermore, we must also establish electronic connections (“EDI compliance”) with the utilities serving particular areas in such states in which we wish to market our services in order to exchange customer usage and billing information.

Although we expect most of these pre-market processes and procedures to be completed by the end of 2017, there can be no assurance that we will be able to achieve all of the arrangements we seek on a timely basis or at all or at an acceptable cost. Consequently, we may not be able to offer service in all of our target markets and failure to do so will adversely affect our ability to grow our business. Loss of licenses or failure to maintain EDI compliance could cause a negative impact on our results of operations, financial condition, and cash flow.

We may not be able to expand geographically as quickly as planned.

Our marketing efforts depend on obtaining licenses from state regulatory authorities and becoming qualified by relevant investor-owned utilities in the geographic areas in which we plan to target customers. To date, these efforts have taken substantially more time than expected. We may incur further delays, which will significantly hinder our marketing efforts and prevent us from reaching our goal for enrollees.

There can be no assurance that we will be able to achieve all the arrangements we seek on a timely basis or at all or at an acceptable cost. Consequently, we may not be able to offer service in all our target markets and failure to do so will adversely affect our ability to grow our business. Loss of licenses or failure to maintain EDI compliance could cause a negative impact on our results of operations, financial condition, and cash flow.

Our marketing efforts may not be successful.

Our marketing strategy recognizes that we will not be the lowest cost provider of electricity to households; instead, we emphasize our value proposition, our brand-building strategy, and other points of differentiation. There is no assurance that our marketing efforts will be successful and, if they are not, we will not be able to build a viable business.

Our cash flow may not be sufficient to sustain our business.

We currently rely on the sale of our Notes, payments on the Term Loan, and payments from custormers to meet our cash needs. There can be no assurance that cash from these sources will continue in sufficient amounts to meet our needs. If we do not have sufficient cash flow, our marketing efforts, assuming they are successful, will be severely constrained and we will not be able to achieve a sufficiently large customer base to sustain our business.

Also, given the amount of Notes that are maturing in the 12 months following issuance, the Company has substantial doubt about its ability to continue as a going concern and is unable to conclude that it is probable that management’s plans will be able to mitigate adverse conditions.

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

Unexpected volatility in prices and constraints in the availability of fuel supplies, particularly natural gas, may have an adverse impact on the cost of the electricity that we sell to our customers. Furthermore, consumption of energy is significantly affected by weather conditions. Typically, colder-than-normal winters and hotter-than-normal summers create higher demand and consumption for natural gas and electricity, respectively, and conversely, milder than normal weather may reduce the demand for energy. Natural gas prices also affect the cost of electricity as it is the fuel of choice for marginal generation requirements. Although we expect to manage our exposure to these movements in wholesale energy prices and customer demand by use of the Exelon PSA, there can be no assurance that this strategy will prove to be successful.

Finally, we may not always choose to pass along increases in costs in order to maintain overall customer satisfaction and this action would have an adverse impact on our margins and results of operations. Alternatively, volatility in pricing related to the cost of energy may lead to increased customer attrition. Changes in these factors, as well as others, could have an adverse effect on our revenues, profitability, and growth, or threaten the viability of our current business model.

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

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

The retail energy business is highly competitive.

We will compete based on value added, price, provision of services, and customer service. Increasing our market share depends in part on our ability to persuade customers to switch to our services. Our retail energy business faces substantial competition both from incumbent utilities as well as from other retail providers, including affiliates of utilities in specific territories. Utilities and other more established competitors have certain advantages such as name recognition, financial strength, and long-standing relationships with customers. Additionally, overall customer demand for electricity may decrease if the prevalence of residential solar panel systems increases. The use of solar panel systems to generate power may allow residential customers to decrease their electricity consumption from providers like us or eliminate it altogether. Persuading potential customers to switch to a new supplier of such important services is challenging. As a result, we may be forced to reduce prices or incur increased costs to gain market share, and we may not always be able pass along increases in commodity costs to customers. Existing or future competitors may have greater financial, technical, or other resources which could put us at a disadvantage. If we are not successful in convincing customers to switch, our business, results of operations, and financial condition will be adversely affected.

2819

Our growth depends on our ability to enter new markets.

We evaluate new markets for our business based on many factors, including the regulatory environment and our ability to procure energy to serve customers in a cost-efficient manner. We may expend substantial effort to obtain required licenses and connections with local distribution companies. Furthermore, there are regulatory differences between the markets that we currently operate in and new markets, including, but not limited to, exposure to credit risk, additional churn caused by tariff requirements, rate-setting requirements, and incremental billing costs. We may also incur significant customer acquisition costs.

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

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

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

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

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

Certain programs required by state regulators have been implemented by utilities in many of the service territories in which we intend to operate, one of which is purchase of receivables or POR. These programs are important to our control of bad debt. In the event that POR programs were to be revised or eliminated by state regulators or individual utilities, we would need to adjust our current strategy regarding customer acquisition and our focus on the growth of our customer base. We would also need to adjust our current business plan to reduce our exposure to customers who may pose a bad debt risk. Any failure to properly respond to changing conditions could adversely affect our results of operations and profitability. See also “Item 1 - Business – Credit Risk Management”.

2920

Our business is subject to complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and results of operations.

We are subject to the jurisdiction of federal and state authorities, including FERC, the CFTC, the SEC, the Federal Trade Commission, and the public utilities commissions of the states in which we do business as well as the market rules and tariffs of the ISOs of which we are a member. These rules and regulations are subject to legislative change, judicial interpretation, and regulatory actions, any which may increase our costs and adversely impact our business.

Changes in, revisions to, or reinterpretations of existing laws and regulations, for example, with respect to prices at which we may sell electricity, or competition in its generation and sale, may have an adverse effect on our businesses. For example, many electricity markets have rate caps, and changes to these rate caps by regulators can impact future price exposure. Similarly, regulatory changes can result in new fees or charges that may not have been anticipated when existing retail contracts were drafted, which can create financial exposure. For example, mandates to purchase a certain quantity or type of electricity capacity can create unanticipated costs. Our ability to manage cost increases that result from regulatory changes will depend, in part, on how the “change in law provisions” of our contracts are interpreted and enforced, among other factors.

Operators of systems providing for the delivery of natural gas and electricity maintain detailed tariffs that are kept on file with regulators. These tariffs and market rules applicable to operators are often very long and complex, and often are subject to service provider proposals to change them. We may not be able to prevent adoption of adverse tariff changes. Users of energy delivery systems also have rules and obligations applicable to them that are established by regulators. For instance, transactions involving a shipper’s release of interstate pipeline capacity are subject to regulation at the federal level. Our failure to abide by tariffs, market rules, or other delivery system rules may result in fines, penalties, and damages.

We are also subject to regulatory scrutiny in all of our markets that can give rise to compliance fees, licensing fees, or enforcement penalties. Regulations vary widely in the markets in which we operate, and these regulations change from time to time. Failure to follow prescribed regulatory guidelines could result in customer complaints and regulatory sanctions.

In addition, regulators are continuously examining certain aspects of our industry. For example, a number of public utility commissions in the Northeast are investigating the impact of the harsh weather conditions during the 2013-2014 winter season on consumers in their territories due to the number of consumer complaints attributable to high bills for the winter season and are urging FERC to investigate circumstances during that period in wholesale energy markets. This heightened regulatory scrutiny resulted in additional obligations on retailers in various markets to provide more detailed disclosures to consumers as well as additional and more stringent requirements on notifying customers when their fixed contract converts to variable pricing. These new regulations could adversely affect our customer attrition rates and cause us to incur higher compliance costs. To the extent any of these commissions takes further regulatory action to address these complaints, such as imposing limits on products, services, rates or other business limitations, our business prospects in these regions could be materially adversely affected.

3021

Finally, door-to-door marketing and outbound telemarketing may become a significant part of our marketing efforts. Each of these channels is continually under scrutiny by state and federal regulators and legislators. Additional regulation or restriction of these marketing practices could negatively impact our customer acquisition plan, and therefore our financial results and our ability to pay the ~~notes~~Notes.

We may make poor investment choices~~, or be subject to a conflict of interest~~.

Aspirity Financial ~~will~~is be in the business of lending money to companies and households for energy related purposes,. asSome ~~well~~or asall ~~continuing~~of the parties towhich ~~provide~~borrow ~~funds~~from tous ~~Enterprises~~may ~~and~~be ~~financing~~unable ~~our~~to ~~own~~repay ~~liquidity~~their ~~needs.~~obligations, ~~There~~which ~~may~~would behave ~~conflicting~~a ~~demands~~material ~~for~~adverse ~~cash~~effect ~~from~~on ~~multiple sources~~us.

~~Because~~We ~~Mr.~~may ~~Krieger~~be issubject ~~both~~to a ~~significant owner of Aspirity and the owner of Enterprises, there may be a~~ conflict of interest ~~in determining how liquidity is used~~.

InAspirity ~~addition,~~Financial ~~some~~has orloaned ~~all~~money ofto ~~the~~Enterprises. ~~parties~~Because ~~which~~Mr. ~~borrow~~Krieger ~~from~~is usboth ~~may~~a besignificant ~~unable~~owner toof ~~repay~~Aspirity ~~their~~and ~~obligations,~~the ~~which~~owner ~~would~~of ~~have~~Enterprises, there may be a ~~material adverse~~conflict ~~effect~~of oninterest usin determining how liquidity is used.

We need substantial liquidity to operate our business.

Historically, we have funded our operations through borrowings from related and unrelated parties and internally generated cash flows. Beginning in May 2012, we began a direct public offering of our Notes. Up to ~~February~~April 2924, ~~2016~~2017, we have sold $3142,~~366~~350,000 of Notes for cash and paid $611,~~231~~801,000 of redemptions, for a net raise to date of $2530,~~135~~550,000, exclusive of offering costs. As of ~~March~~April 3024, ~~2016~~2017, there were $2530,~~059~~550,000 of Notes outstanding. The Notes Offering supplies us with liquidity to operate. However, we may not be able to obtain sufficient funding for our future operations from such source to provide us with necessary liquidity. Difficulty in obtaining adequate credit and liquidity on commercially reasonable terms may adversely affect our business, prospects, and financial condition. Based on the amount of current maturities and the nature of the Notes, the Company has concluded there is substantial doubt about its ability to continue as a going concern.

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

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

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

3122

We have determined that our disclosure controls and procedures and our internal control over financial reporting are currently not effective which could adversely affect our ability to accurately report our financial results.

We concluded that as of December 31, 2016, our disclosure controls and procedures were not effective. Until we have been able to test the operating effectiveness of our remediated internal controls and ensure the effectiveness of our disclosure controls and procedures, any material weaknesses may materially adversely affect our ability to report accurately our financial condition and results of operations in the future in a timely and reliable manner. In addition, although we continually review and evaluate internal control systems to allow management to report on the sufficiency of our internal controls, we cannot assure you that we will not discover additional weaknesses in our internal control over financial reporting. Any such additional weakness or failure to remediate the existing weakness could materially adversely affect our ability to comply with applicable financial reporting requirements. If that were to occur, purchasers of our Notes could be using inaccurate financial information with which to make their investment decision.

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

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

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

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

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

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

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

Please refer to our Prospectus for additional risk factors related to the Notes.

Item 1B – Unresolved Staff Comments

Not applicable.

Item 2 – Properties

Our headquarters is located at 701 Xenia Avenue South, Suite 475, Minneapolis, MN 55416, telephone (463) 432-1500. Our sub-lease is for 8,003 square feet, expires on May 31, ~~2019~~2017, and the monthly rent is $10,671. ~~We do not engage in any production or manufacturing activities, and we do not have any environmental issues related to our operations.~~

On March 24, 2017, we signed a new lease for headquarters office space at 12800 Whitewater Drive, Minneapolis MN 55343. Our lease is for approximately 7,200 square feet, expires on October 31, 2024, and calls for average monthly occupancy expenses for the first lease year commencing June 1, 2017 of $9,209, consisting of rent and operating expenses of $3,413 and $5,796, respectively.

We do not engage in any production or manufacturing activities, and we do not have any environmental issues related to our operations.

Item 3 – Legal Proceedings

See “Item 8 - Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note 1916 Commitments and Contingencies”.

Item 4 – Mine Safety Disclosures

Not applicable.

3224

Part II

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

Not applicable.

Use of Proceeds of Notes Offering

We registered $75 million of Notes under our New S-1. Since renewals reduce the aggregate amount of registered securities available for sale but generate no additional cash, we have based our use of proceeds on the estimated maximum net proceeds we expect to receive from initial sales. If all $75 million of Notes are sold, and the renewal rate remains consistent with the historic levels experienced since 2012, we would expect to receive about $50 million of net proceeds after payment of estimated expenses.

The exact amount of net proceeds will vary considerably depending on the duration of the Notes Offering, the maturities of Notes purchased, actual renewal rates, actual advertising and marketing expenses, and other factors. We will not receive the net proceeds in a single closing and will use the proceeds as we sell Notes.

We expect to apply net proceeds to the following corporate purposes, listed in order of priority with the expected level of expenditure being detailed in the table that follows:

● General working capital: will be used to fund our start-up operations and will likely include the payment of general and administrative expenses, such as salaries for the personnel necessary to begin operations; ● Retail energy customer list acquisitions: one way we intend to build our retail energy business through Aspirity Energy and its operating subsidiaries; ● Commercial energy financings: Aspirity Financial will make commercial loans to businesses operating in the energy industry, including making additional loans to Enterprises, probably of at least $5,000,000; ● Retail energy entity acquisitions: another way we may build our retail energy business although we have no current targets; and ● Consumer financing: Aspirity Financial may make loans to individuals and households, however this will not begin until after we have our retail energy operations established, if at all.

The following table summarizes the above information regarding our intended use of $50 million of net proceeds, and sets forth our expected allocation of the net proceeds if we raise less than that amount:

Use of proceeds	Dollars (000s)		Percent			Dollars (000s)		Percent			Dollars (000s)		Percent
General working capital	$	7,500		15	%	$	4,000		16	%	$	3,000		20	%
Retail energy customer list acquisitions		10,000		20	%		5,000		20	%		4,000		27	%
Commercial energy financings		20,000		40	%		10,000		40	%		5,000		33	%
Retail energy entity acquisitions		10,000		20	%		5,000		20	%		3,000		20	%
Consumer financing		2,500		5	%		1,000		4	%		—		0	%
Net proceeds	$	50,000		100	%	$	25,000		100	%	$	15,000		100	%

Item 6 – Selected Consolidated Financial Data

~~The~~Not ~~following table sets forth selected consolidated financial data for the last two years derived from the audited consolidated financial statements of Aspirity Holdings LLC~~applicable.

The information is only a summary and you should read it in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” beginning on page 40 and our consolidated financial statements and notes thereto found in “Financial Statements and Supplementary Data” beginning on page 61.25

Dollars in thousands unless otherwise indicated	Years ended December 31
	2015			2014
Statements of Operations Data
Net revenue	$	48,124		$	49,841
Total operating expenses		52,489			43,402
Operating income (loss)		(4,365	)		6,440
Net other income (expense)		(444	)		(2,661	)
Income (loss) before income taxes		(4,809	)		3,779
Income tax benefit		(47	)		-
Net income (loss)		(4,762	)		3,779
Preferred distributions		(549	)		(549	)
Noncontrolling interests		(468	)		-
Net income attributable to common	$	(4,843	)	$	3,230
Ratio of earnings to fixed charges (1)		-0.21	x		2.47	x
Balance Sheet Data
Cash and trading deposits	$	10,379		$	23,497
Total assets		28,999			31,770
Total debt		27,630			19,288
Total liabilities		37,050			29,072
Total members’ equity		1,098			2,698

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

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

The following discussion (the “MD&A”) should be read in conjunction with our consolidated financial statements and notes thereto and other information appearing elsewhere in this report.

Forward Looking Statements

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

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

● ~~Expected~~Changes ~~operating~~in ~~results~~commodity prices, ~~such~~● asExtreme ~~revenue~~and ~~growth~~unpredictable ~~and~~weather ~~earnings;~~conditions, ● ~~Anticipated~~The ~~levels~~sufficiency of ~~capital~~risk ~~expenditures~~management and ~~expansion~~hedging ofpolicies, ~~our~~● ~~retail~~Customer ~~electricity~~concentration, ~~business~~● ~~segment;~~Federal, ●state ~~Current~~and orlocal ~~future~~regulation, ~~price~~including ~~volatility~~the inindustry’s ability to prevail on its challenge to the ~~energy~~New ~~markets~~York ~~and~~Public ~~future~~Service ~~market~~Commission’s ~~conditions;~~order ●enacting ~~Our~~new ~~belief~~regulations that wesought ~~have~~to ~~sufficient~~impose ~~liquidity~~significant tonew ~~fund~~restrictions ~~our~~on ~~operations~~retail ~~during~~energy ~~the~~providers ~~next~~operating 12in ~~months;~~New York, ● ~~Expectations~~Key oflicense ~~the~~retention, ~~effect~~● onIncreased ~~our~~regulatory ~~financial~~scrutiny ~~condition~~and ofcompliance ~~claims~~costs, ~~litigation,~~● ~~environmental~~Our ~~costs,~~ability ~~contingent~~to ~~liabilities,~~borrow funds and ~~governmental~~access ~~and~~credit ~~regulatory~~markets, ~~investigations~~● ~~and~~Restrictions ~~proceedings;~~in our debt agreements and ●collateral ~~Our~~requirements, ~~strategies~~● ~~for~~Credit risk ~~management.~~with respect to suppliers and customers,

●	Level of indebtedness,

●	Changes in costs to acquire customers,

●	Actual customer attrition rates,

●	Actual bad debt expense in non-POR markets,

●	Accuracy of billing systems,

●	Ability to successfully navigate entry into new markets,

●	Whether our majority shareholder or its affiliates offers us acquisition opportunities on terms that are commercially acceptable to us,

●	Ability to integrate acquisitions into our operations successfully and efficiently,

●	Competition, and

●	The “Risk Factors” appearing under the caption “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016, and in our quarterly reports, other public filings, and press releases.

Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can it assess the impact of each of these factors on the businesses of the Company or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

These statements are qualified in their entirety by reference to, and are accompanied by, the factors detailed in “Risk Factors” of this Form 10-K, in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements that could cause our actual results to differ materially from those indicated in the forward-looking statements.

The risk factors and forward looking statements described involve risks and uncertainties and 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, financial condition, or results of operations.

~~Important~~The ~~Note Regarding Recent Restructuring~~Company

OnAspirity ~~the~~is ~~Distribution~~a ~~Date,~~holding ~~the~~company ~~Company~~that ~~completed~~conducts aits ~~significant~~operations ~~Restructuring~~principally bythrough ~~distributing~~wholly-owned ~~100%~~subsidiaries. ofOur ~~the~~roots ~~equity~~go ~~interests~~back ofto ~~Enterprises~~2005 and toin ~~its~~2015 ~~members~~we restructured. ~~Enterprises~~The ~~was~~restructuring aincluded ~~first~~the ~~tier,~~sale ~~wholly~~of ~~owned~~a subsidiary ofand the ~~Company,~~spinoff ~~which~~of ~~held~~Enterprises ~~nearly~~and ~~all~~its oflegacy ~~the Company’s~~ business segments ~~operations.~~of ~~The~~wholesale ~~details~~trading, ofdiversified ~~the~~investments, ~~Restructuring~~and ~~are~~the ~~described~~retail ~~above~~business ~~under~~operated ~~“The~~by ~~Restructuring”~~REH.

~~While~~Today, we ~~no longer~~ have antwo ~~ownership~~first-tier ~~interest~~operating ~~in Enterprises and its~~ subsidiaries, an- ~~assessment~~Aspirity ofEnergy ~~the~~in ~~relationship~~retail ~~between~~energy ~~the~~services ~~Company~~ and ~~Enterprises~~Aspirity ~~following~~Financial ~~the~~which ~~Distribution was performed because Timothy Krieger is a~~ provides energy-related ~~party~~financial ofservices ~~both~~to ~~Aspirity~~businesses and ~~Enterprises, and because the entities have an ongoing business relationship resulting from the Term Loan~~households. ~~Aspirity~~Even ~~holds~~though ~~a variable interest in Enterprises in~~ the ~~form~~Company ofhas ~~the~~existed ~~Term~~since ~~Loan~~2005, ~~making~~since ~~Enterprises a VIE. Following~~ the ~~Distribution Date, Aspirity will be the primary~~restructuring ~~beneficiary of the VIE and will consolidate Enterprises. While the Company will include the assets and net income of Enterprises~~ in ~~its~~2015 ~~consolidated financial statements,~~ the Company ~~does~~has ~~not~~operated ~~have rights to those assets other than pursuant to its rights under the Term Loan. We will reevaluate the status of Enterprises~~ as a ~~VIE~~start-up onand aour ~~regular~~financial ~~basis.~~results ~~See~~for ~~“Critical~~2015 ~~Accounting~~and ~~Policies –~~2016 ~~Variable~~reflect ~~Interest~~that ~~Entities”~~status.

~~Much~~Through the end of the ~~discussion~~first ~~that~~quarter ~~follows~~of ~~focuses~~2016, on our ~~operations~~financial ~~prior~~results towere ~~the~~consolidated ~~Restructuring.~~with ~~Our~~those ~~financial~~of ~~condition~~Enterprises. ~~and~~Enterprises ~~operations~~is ~~will~~the parent becompany ~~significantly~~of ~~different~~REH, ~~from~~a ~~prior~~company ~~periods~~in ~~because~~the wesame ~~have~~business ~~distributed~~as ~~all~~us - the sale of ~~our~~electricity ~~Legacy~~to ~~Businesses~~retail customers. ~~Going forward~~Accordingly, weour ~~no longer~~statement ~~have~~of ~~any~~operations ~~wholesale~~included ~~trading~~results ~~activities,~~generated ~~which~~by ~~historically~~REH ~~accounted~~through ~~for~~the ~~29.7%,~~end ~~and 77.5%~~ of ~~our total revenues for~~ the ~~years~~first ~~ended December~~quarter 31of 2016, ~~2015~~which ~~and~~were ~~2014, respectively~~significant. ~~While~~We weno ~~have~~longer consolidate ~~begun~~Enterprises ~~new~~or ~~retail~~its ~~energy~~subsidiaries, ~~service~~after ~~activities within~~ the ~~last~~first ~~few months~~quarter, our ~~historical~~ financial statements ~~reflect~~include ~~the~~only ~~results from the operations of~~ our ~~former~~results ~~retail~~and, ~~energy service activities through REH~~consequently, period-by-period ~~which~~comparisons webetween no2015 ~~longer~~and ~~own~~2016 orare ~~operate~~not comparable.

Prior to the start of the Restructuring, the Company’s name was Twin Cities Power Holdings and its active first tier subsidiaries consisted of Apollo, TCP, CTG, Cygnus, REH, and Cyclone. These subsidiaries operated in three major business segments – wholesale trading, retail energy services, and diversified investments. As part of the Restructuring, the Company has exited these Legacy Businesses.27

The Company is now in the process of beginning operations in two business segments - retail energy, which we will operate through Aspirity Energy and financial services, which we will operate through Aspirity Financial. In connection with the Exelon PSA, we merged AENE and AEMS into Aspirity Energy. Aspirity Energy will then serve retail customers in the PJM, MISO, NYISO, and ISO-NE footprints and its wholly owned subsidiary, AES, will serve those in ERCOT.

Until we are able to generate revenue from our new Aspirity Energy operations, our cash flows will be derived almost entirely from payments we receive from Enterprises on the Term Loan and the sale of Notes.

Operations Prior to the Restructuring

Prior to the Restructuring, through wholly-owned subsidiaries, the Company traded financial and physical electricity contracts in North American wholesale markets regulated by FERC and operated by ISOs and RTOs, traded energy derivative contracts on exchanges regulated by the CFTC, including ICE, NGX, and CME, provided electricity supply services to retail customers in certain states that permit retail choice, and was engaged in certain asset management activities, including real estate development and investments in privately held businesses. Consequently, we used to have three major business segments used to measure our activity – wholesale trading, retail energy services, and diversified investments.

Wholesale Trading

In general, the Company’s trading activities, which were done through TCP, CTG, and Cygnus, were 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. The ISO-traded financial contracts known as “virtuals”, i.e., INCs, DECs, and UTCs, are outstanding overnight, and settle the next day. FTRs are also offered by the ISOs and may be outstanding overnight or longer. The Company also traded electricity and other energy derivatives on ICE, NGX, and CME.

For the years ended December 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.

As a result of the Restructuring, the Company is no longer involved in the wholesale trading business as the sale of TCP and SUM to Angell closed on June 1, 2015 and CTG and Cygnus were transferred as of the Distribution Date. We do not intend to engage in wholesale trading in the future.

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. The business was renamed TSE and beginning on July 1, 2012, the Company began selling electricity to retail accounts. During late 2012 and early 2013, we applied for retail electricity supplier licenses for the states of Massachusetts, New Hampshire, and Rhode Island which were issued on various dates in 2013. On January 2, 2014, we acquired a retail energy business now known as TSEE and licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio. The equity interests of TSE and TSEE were held by REH. The 8 states in which REH’s subsidiaries were licensed incorporated the service territories of 33 investor-owned electric utilities and as of December 31, 2015, REH was actively marketing its services in 29 of these.

Effective with the Distribution Date, we no longer own REH. However, we began to compete in the retail energy business as Aspirity Energy and we intend expand these operations as we receive the necessary licenses and establish the necessary relationships with utilities.

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 acquired and intended to develop land for resale, either as improved sites for construction of single- and multi-family homes or as completed dwellings. Properties owned by Cyclone include Fox Meadows Townhome Project, Territory House Project, and the Texas Avenue Project. At various dates during 2014 up to and including September 1, 2015, we also acquired certain private investments, including the Series C Convertible Promissory Notes of Ultra Green Packaging, Inc. (the “Series C Notes” and “Ultra Green”, respectively), the Angell Note, and a controlling equity interest in Noble.

In connection with the Restructuring, the Company transferred Cyclone and its private investment portfolio to Enterprises and we do not intend to engage in these types of diversified investment activities in the future.

Derivative Instruments

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

During 2014, we acquired the majority of our FTRs in auctions conducted by ISOs, including MISO, PJM, NYISO, ISO-NE, and ERCOT. We initially recorded these FTRs at the auction price less the obligation due to the ISO, typically zero, and subsequently adjusted 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 traded, changes in the fair value of FTRs were included in our wholesale trading revenues. As of May 31, 2015, we no longer had any open FTR positions.

REH’s retail business is exposed to volatility in the cost of energy acquired for sale to customers, and as a result, we used derivatives to hedge or reduce this variability. REH follows 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. REH’s risk management policies also permit the use of undesignated derivatives as “economic hedges”. For an undesignated economic hedge, all changes in the derivative financial instrument’s fair value are recognized currently in revenues.

Effective with the Distribution Date, we no longer own Enterprises and its associated derivative instruments.

The table below details the open derivative contracts held for trading purposes, as undesignated, economic hedges by our retail segment, and as cash flow hedges by our retail segment as of December 31, 2015 and 2014.

Open Derivative Contracts Held for Trading

As of December 31, 2015

Date, segment and		Delivery		Final	Energy		Fair Value
contract type	Hub or zone	period		settlement	(MWh)		Asset		Liability
Wholesale Trading
Electricity futures	AESO		Q1 2016	various		8,680	$	22,086	$	56,639
Electricity futures	AESO		Q2 2016	various		22,200		29,551		137,623
Subtotal						30,880		51,636		194,262
Retail Energy Services Economic Hedges
Electricity futures	PJM West Hub		Q1 2016	various		6,720		2,268		5,764
Electricity futures	PJM West Hub		Q2 2016	various		5,120				21,188
Electricity futures	PJM West Hub		Q3 2016	various		5,120		18,800		8,988
Electricity futures	PJM West Hub		Q4 2016	various		5,040				30,156
Subtotal						22,000		21,068		66,096
Totals						52,880	$	72,704	$	260,358

As of December 31, 2014

Date, segment and		Delivery		Final		Energy		Fair Value
contract type	Hub or zone	period		settlement		(MWh)		Asset		Liability
Wholesale Trading
Electricity futures	PJM West Hub		daily		daily		6,400	$	22,400	$	-
FTRs	MISO, NYISO, PJM		Q1 & Q2 2015		various		8,981,440		1,435,819		-
Electricity futures	AESO		Q1 2015		various		80,320		785,617		286,250
Electricity futures	AESO		Q2 2015		various		135,600		892,838		1,094,059
Electricity futures	AESO		Q3 2015		various		78,120		601,993		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

Years Ended December 31, ~~2015~~2016 and ~~2014~~2015

After the spinoff of Enterprises on November 1, 2015 but prior to March 30, 2016, the financial results of Enterprises were consolidated with those of the Company as a variable interest entity or VIE.

On March 18, 2016, FERC approved the change in control of the Company per Docket No. EC16-60-000. This allowed the Company to adopt an amended and re-stated Operating Agreement which converted outstanding Class B units (certain financial rights only) to Class A units (full financial and governance rights) on March 30, 2016. This constituted a reconsideration event and as such, a reassessment of the VIE relationship between the Company and Enterprises and the consolidation decision was performed as of this date.

While Enterprises is still a VIE due to lack of sufficient equity investment to finance its activities without additional subordinated financial support and Aspirity continues to hold a variable interest in the form of the Term Loan, for Aspirity to consolidate Enterprises, it must be either the primary beneficiary of its operations, or hold a controlling financial interest, either by contract or via related party considerations. After March 30, 2016, Aspirity meets neither of these requirements. Specifically, Timothy Krieger as an individual is the primary beneficiary of Enterprises as he meets both the power and losses/benefits criteria.

With the spinoff, the Company exited all wholesale trading and diversified investment activity and has no plans to engage in such in the future, therefore these operations are reported in our 2016 SEC filings and GAAP financials as discontinued operations.

However, although we no longer owned REH after the spinoff, GAAP requires that we report its business as a continuing operation through March 30, 2016 since it was not considered to be a “strategic shift” from future operations.

The following table shows the effects of the consolidation of Enterprises’ retail energy operations on our consolidated statements of operations for 2016 and 2015.

Consolidating Statement of Operations Data
Dollars in thousands	Aspirity Holdings & Subsidiaries			Krieger Enterprises & Subsidiaries			Eliminations			Aspirity Holdings Consolidated

For Year Ended Dec 31, 2016
Retail energy services	$	2,095		$	9,583		$	-		$	11,678
Financial services		2,579			-			(715	)		1,864
Total revenue		4,673			9,583			(715	)		13,542
Total costs of revenues & operations		12,136			9,742			-			21,878
Operating loss		(7,462	)		(159	)		(715	)		(8,336	)
Interest expense		(4,260	)		(677	)		609			(4,328	)
Other income (expense), net		(349	)		119			-			(230	)
Loss from continuing operations		(12,072	)		(717	)		(105	)		(12,894	)
Net income (loss) from:
Continuing operations		(12,072	)		(717	)		(105	)		(12,894	)
Discontinued operations		-			607			105			712
Net loss		(12,072	)		(110	)		-			(12,181	)

Net loss attributable to non-controlling interest		-			(110	)		-			(110	)
Net loss attributable to the Company		(12,072	)		-			-			(12,072	)
Preferred distributions		549			-			-			549
Net loss attributable to common	$	(12,621	)	$	-		$	-		$	(12,621	)

For Year Ended Dec 31, 2015
Retail energy services	$	-		$	30,109		$	-		$	30,109
Financial services		2,877			-			(2,877	)		-
Total revenue		2,877			30,109			(2,877	)		30,109
Total costs of revenues & operations		3,780			32,888			-			36,668
Operating loss		(903	)		(2,779	)		(2,877	)		(6,559	)
Interest expense		(3,206	)		(2,140	)		2,877			(2,468	)
Other income (expense), net		(109	)		275			-			165
Loss from continuing operations		(4,218	)		(4,644	)		-			(8,862	)
Net income (loss) from:
Continuing operations		(4,218	)		(4,644	)		-			(8,862	)
Discontinued operations		-			4,100			-			4,100
Net loss		(4,218	)		(544	)		-			(4,762	)
Net loss attributable to non-controlling interest		-			(468	)		-			(468	)
Net loss attributable to the Company		(4,218	)		(76	)		-			(4,294	)
Preferred distributions		549			-			-			549
Net loss attributable to common	$	(4,767	)	$	(76	)	$	-		$	(4,843	)

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

	For the Years Ended December 31,
Dollars in thousands; may not add	2015						2014						Increase (decrease)
Dollars in thousands;	2016						2015						Increase (decrease)
due to rounding	Dollars			Percent			Dollars			Percent			Dollars			Percent
may not add due to rounding	Dollars			Percent			Dollars			Percent			Dollars			Percent
Revenue
Wholesale trading revenue, net	$	14,293			29.7	%	$	38,612			77.5	%	$	(24,318	)		-63.0	%
Retail energy services.	$	11,678			86.2	%	$	30,109			100.0	%	$	(18,431	)		-61.2	%
Retail energy services		30,483			63.3	%		11,229			22.5	%		19,253			171.5	%
Financial services (Note 13)		1,864			13.8	%		-			0.0	%		1,864			na
Diversified investments		3,348			7.0	%		-			0.0	%		3,348			na
Net revenue		13,542			100.0	%		30,109			100.0	%		(16,567	)		-55.0	%
Total sales & services revenue		33,831			70.3	%		11,229			22.5	%		22,601			201.3	%
Net revenue		48,124			100.0	%		49,841			100.0	%		(1,717	)		-3.4	%
Costs of sales & services
Cost of retail electricity sold		2610,~~663~~010			5573.49	%		1126,~~441~~663			2388.06	%		15(16,~~222~~653	)		~~133~~-62.15	%
Cost of real estate sold		319			0.7	%		-			0.0	%		319			na
Gross profit (loss)		3,533			26.1	%		3,446			11.4	%		87			2.5	%
Cost of construction services		1,704			3.5	%		-			0.0	%		1,704			na
Total		28,686			59.6	%		11,441			23.0	%		17,246			150.7	%
Gross profit (loss)		5,144			10.7	%		(211	)		-0.4	%		5,356			2435.8	%
Operating expenses
Sales & marketing		1,353			2.8	%		325			0.7	%		1,028			316.4	%
Sales, marketing, and customer service		5,038			37.2	%		1,333			4.4	%		3,705			278.0	%
Compensation & benefits		13,468			28.0	%		21,722			43.6	%		(8,254	)		-38.0	%
Other general & administrative		6,831			50.4	%		8,672			28.8	%		(1,841	)		-21.2	%
Professional fees		2,463			5.1	%		2,487			5.0	%		(24	)		-1.0	%
Total operating expenses		11,869			87.6	%		10,005			33.2	%		1,864			18.6	%
Other general & administrative		5,226			10.9	%		6,094			12.2	%		(868	)		-14.2	%
Operating income (loss)		(8,336	)		-61.6	%		(6,559	)		-21.8	%		(1,777	)		27.1	%
Trading tools & subscriptions		1,293			2.7	%		1,333			2.6	%		(40	)		-3.0	%
Total operating expenses		23,803			49.5	%		31,961			64.1	%		(8,158	)		-25.5	%
Operating income (loss)		(4,365	)		-9.1	%		6,440			12.9	%		(10,890	)		-167.8	%
Other income (expense)
Interest expense		(34,~~569~~328	)		-732.40	%		(2,~~293~~468	)		-48.62	%		(1,~~275~~859	)		5575.63	%
Interest income		829			1.7	%		143			0.3	%		686			480.2	%
Other income		(230	)		-1.7	%		165			0.5	%		(395	)		-239.2	%
Gain on sale of subsidiary		1,343			2.8	%		-			0.0	%		1,343			na
Other income (expense), net		(4,558	)		-33.7	%		(2,303	)		-7.6	%		(2,255	)		97.9	%
Impairment of convertible notes		(1,250	)		-2.6	%		-			0.0	%		(1,250	)		na
Net income (loss) from continuing operations		(12,894	)		-95.2	%		(8,862	)		-29.4	%		(4,032	)		45.5	%
Gain (loss) on foreign currency
Net income (loss) from discontinued operations		712			5.3	%		4,100			13.6	%		(3,387	)		-82.6	%
exchange		356			0.7	%		(721	)		-1.4	%		1,077			49	%
Net income (loss)		(12,181	)		-89.9	%		(4,762	)		-15.8	%		(7,419	)		155.8	%
Gain on sale of
Net income (loss) from non-controlling interest		(110	)		-0.8	%		(468	)		-1.6	%		359			-76.6	%
marketable securities		(130	)		-0.3	%		66			0.1	%		(195	)		-298	%
Net income (loss) attributable to Company		(12,072	)		-89.1	%		(4,294	)		-14.3	%		(7,778	)		181.2	%
Other income		1,976			4.1	%		145			0.3	%		1,831			1261	%
Preferred distributions		549			4.1	%		549			1.8	%		-			0.0	%
Other income (expense), net		(444	)		-0.9	%		(2,661	)		-5.3	%		2,217			83.3	%
Net income (loss) attributable to common	$	(12,621	)		-93.2	%	$	(4,843	)		-16.1	%	$	(7,778	)		160.6	%
Income before income taxes		(4,809	)		-10.0	%		3,779			7.6	%		(8,588	)		-227.3	%
Income tax provision		(47	)		-0.1	%		-			0.0	%		(47	)		na
Net income (loss)		(4,762	)		-9.9	%		3,779			7.6	%		(8,541	)		-226.0	%
Net income (loss) attributable to non-controlling interest		(468	)		-1.0	%		-			0.0	%		(468	)		na
Net income (loss) attributable to Company		(4,294	)		-8.9	%		3,779			7.6	%		(8,073	)		-213.6	%
Preferred distributions		(549	)		-1.1	%		(549	)		-1.1	%		-			0.0	%
Net income attributable to common	$	(4,843	)		-10.1	%	$	3,230			6.5	%	$	(8,073	)		-249.9	%

40Revenue: For the years ended December 31, 2016 and 2015, on a consolidated basis, retail energy revenue was $11,678,000 and $30,109,000, respectively, a decrease of $18,431,000. In 2016, $2,095,000 of this revenue was generated by Aspirity Energy for the full year and $9,583,000 by REH through March 30, 2016. Revenue for 2015 was produced solely by REH.

~~Wholesale~~The ~~trading~~remainder ~~revenue:~~of In2016’s ~~our~~total ~~wholesale~~revenue ~~trading~~of ~~business~~$13,542,000 weincludes ~~record~~$1,864,000 ~~revenues~~of ~~based~~financial ~~upon~~services ~~changes~~revenue inor interest income on the ~~fair~~Term ~~values~~Loan ofearned ~~the~~by ~~contracts we~~Aspirity ~~trade,~~Financial ~~net~~through ofOctober ~~costs~~31, 2016. ~~The~~Due ~~initial~~to ~~recognition~~Amendment 3 of ~~fair~~the ~~value~~Term ~~and~~Loan, ~~subsequent~~financial ~~changes~~services inrevenue was ~~fair~~not ~~value~~recognized ~~affect~~after ~~reported~~November ~~earnings~~1, ~~in the~~2016 ~~period~~due ~~the~~to a change ~~occurs~~in accounting method. ~~The~~Subsequent ~~fair~~to ~~values~~November of1, ~~instruments~~2016, ~~that~~the ~~remain~~cost ~~open~~recovery method atwill abe ~~balance~~used ~~sheet~~account ~~date~~for ~~represent~~income ~~unrealized~~related ~~gains or~~to ~~losses~~the Term loan. ~~Our~~All ~~primary~~payments ~~costs~~received inafter ~~generating~~the ~~trading~~amendment ~~revenue~~were ~~are~~recognized ~~compensation~~as equity ofcontributions ~~our~~and ~~energy~~reductions ~~traders~~to asthe ~~well~~principal asof the ~~interest~~loan. ~~expense~~Under this method, cash receipts are first applied to reduce ofthe ~~obtaining~~principal balance of the ~~capital~~receivable ~~necessary~~and second to ~~post~~income ~~collateral~~after all principal has been repaid.

~~Generally,~~See ~~our~~“Note ~~greatest~~10 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~~Term ofLoan” ~~market turbulence, prices tend~~ to ~~be volatile, which give our traders~~ the ~~opportunity~~financial ~~to take advantage of such volatility~~statements. ~~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.30

Market conditions during 2015 were characterized by milder than normal weather, with 207 fewer heating degree-days than normal (down 5%), 150 more cooling degree-days than normal (up 11%), modestly above-normal average temperatures (54.4°F versus 53.7°F), and cheaper natural gas, down about 32% to $2.63/MCF versus the 5-year average of $3.85/MCF.

Comparing 2015 to 2014, 2015 was warmer; HDDs for the U.S. were 4,125 or 10% below 2014’s figure of 4,608 and CDDs during 2015 totaled 1,458 or 15% more compared to 1,272 in 2014. For 2015, the Henry Hub natural gas spot price averaged $2.63/MCF, 40% below 2014’s $4.37 mark. Supplies of gas during 2015 were good. Weekly storage levels averaged 2,768 BCF or 25% more than 2014’s level of 2,222 and 2% above the 5-year average of 2,722.

	Years Ended December 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		4,125		4,608		4,332		(483	)		-10	%		(207	)		-5	%
Cooling degree-days		1,458		1,272		1,308		186			15	%		150			11	%
Avg temperature (°F)		54.4°F		52.5°F		53.7°F		1.9°F			4	%		0.7°F			1	%
Natural Gas
Henry Hub spot price ($/MCF)		2.63		4.37		3.85		(1.74	)		-40	%		(1.22	)		-32	%
Working gas in underground storage, Lower 48 states, storage, Lower 48 states, EIA weekly estimates (BCF)		2,768		2,222		2,722		546			25	%		46			2	%

1 - “LTA” abbreviates long term average. For weather data, the 30 year period is 1985-2014 and for natural gas the 5 year eriois 2009-2013.

The average for the day-ahead PJM West Hub peak price during 2015 was $41.52/MWh with a standard deviation of $20.72 resulting in a coefficient of variation of 50%, compared to $58.65/MWh, $54.81, and 93% for 2014. The high for the year was $237.48/MWh and the low was $23.25. As shown by the table below, price levels and volatility were generally lower in 2015 as compared to 2014. Most of the high prices and volatility of 2014 and 2015 occurred in the first quarters of such years.

PJM West Hub Peak Day Ahead	Years Ended December 31,
							Increase (decrease)
	2015			2014			Units			Percent
Price ($/MWh)
Average		41.52			58.65			(17.13	)		-29	%
Maximum		237.48			655.75			(418.27	)		-64	%
Minimum		23.25			26.49			(3.23	)		-12	%
Standard deviation		20.72			54.81			(34.08	)		-62	%
Coefficient of variation (stdev ÷ avg)		50	%		93	%		199	%		213	%
Daily percentage changes
Average		1.6	%		2.5	%		-0.9	%		-36	%
Maximum		209.3	%		200.3	%		9.0	%		4	%
Minimum		-63.5	%		-78.1	%		14.6	%		-19	%
Standard deviation		21.3	%		25.8	%		-4.5	%		-18	%
Number of days
Up 10% or more		64			62			2			3	%
Between 10% up and 10% down		130			131			(1	)		-1	%
Down 10% or more		61			62			(1	)		-2	%

On December 30, 2014, FERC accepted the Company’s settlement offer dated November 14, 2014 with respect to the closure of its investigation into the trading activities of certain ex-employees of TCPC in the MISO market during the 13-month period from January 1, 2010 to January 31, 2011. The final settlement agreement called for the payment $3,607,000, consisting of disgorgement of profits of $978,000 and interest thereon of $129,000 to MISO and a civil penalty of $2,500,000 to the U.S. Treasury, with payment first to MISO and then to the Treasury. The non-financial portion required certain improvements to compliance procedures. The disgorgement was recorded as a reduction of revenue and the civil penalty was expensed during the third quarter of 2014. The settlement was booked as a liability of TCP as TCE and TCPC no longer had any employees or operations. The first installment of $500,000 was paid on December 31, 2014 with the remainder due in 16 equal quarterly installments of $194,000 each, beginning April 1, 2015.

On June 1, 2015, all of the equity interests of TCP and its wholly-owned subsidiary SUM were sold to Angell. As the financial obligations under the settlement agreement were on TCP’s books, they were also assumed by Angell in connection with its purchase. For the five months ended May 31, 2015 and the year ended December 31, 2014, revenues and operating income of these entities were $12,909,000 and $13,127,000 and $5,093,000 and $2,720,000, respectively.

As a result of these factors, for the year ended December 31, 2015, net wholesale trading revenue decreased by $24,322,000 or 63% to $14,290,000 compared to $38,612,000 for 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 years ended December 31, 2015 and 2014, we recorded total revenues in our retail segment of $30,109,000 and $12,947,000, respectively. These totals consisted of retail energy sales of $30,483,000 in 2015 and $11,229,000 in 2014, up 171.5% and wholesale trading revenues of $(374,000) and $1,717,000, respectively, down 121.8%. During 2015, retail energy sales revenue increased principally as a result of increases in the number of customers served and MWh sold. The customer base consists largely of residential consumers with a few small commercial accounts.

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

Key Operating Statistics (in units unless otherwise indicated)	For and at years ended December 31,
	For/At Years Ended December 31,
						Increase (decrease)
Key Retail Energy Operating Statistics						Increase (decrease)
	2015			2014		Units			Percent
(in units unless otherwise indicated)		2016			2015		Units			Percent
Retail electricity sales ($000s)		30,483			11,229		19,254			171.5	%
Aspirity
Wholesale trading revenue, net ($000s)		(374	)		1,717		(2,091	)		-121.8	%
Retail electricity sales ($000s)		2,095			na		na			na
Total segment revenues ($000s)		30,109			12,946		17,163			132.6	%
Unit sales (MWh)		27,979			na		na			na
Unit sales (MWh)		346,037			112,378		233,659			-207.9	%
Weighted average retail price (¢/kWh)		7.49			na		na			na
Weighted average retail price (¢/kWh)		8.81			9.99		(1.18	)		-11.8	%
Customers receiving service, end of period		7,170			na		na			na
Customers receiving service, end of period		32,319			9,501		22,818			-240.2	%
REH
Retail electricity sales ($000s)		9,583			30,109		(20,525	)		-68.2	%
Unit sales (MWh)		115,092			346,037		(230,945	)		-66.7	%
Weighted average retail price (¢/kWh)		8.33			8.70		(0.37	)		-4.3	%
Customers receiving service, end of period		—			32,319		na			na
Consolidated
Retail electricity sales ($000s)		11,678			30,109		(18,430	)		-61.2	%
Unit sales (MWh)		143,071			346,037		(202,966	)		-58.7	%
Weighted average retail price (¢/kWh)		8.16			8.70		(0.54	)		-6.2	%
Customers receiving service, end of period		7,170			32,319		(25,149	)		-77.8	%

~~Diversified~~Costs ~~investments~~of retail electricity sold: In general, the Company’s costs of electricity sold include the cost of purchased power, EDC service fees, renewable energy certificates, bad debt expense, and hedge gains net of losses, if any. Wholesale electricity buyers are typically required to maintain cash deposits in separate accounts to meet vendors’ financial assurance requirements to purchase power which amount is included in “cash in trading accounts” or “cash in collateral accounts”.

~~Real~~Electricity ~~Estate~~buyers ~~Development~~that do not use full requirements preferred supply agreements are exposed to volatility in the cost of energy acquired for sale to customers, and consequently, from time to time they may use derivatives to hedge or reduce this variability using hedge accounting guidance as permitted by GAAP. For example, under GAAP, certain derivatives contracts may be designated as cash flow hedges and the effective portion of any change in the derivative or 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. An entity’s risk management policies may also permit the use of undesignated derivatives as economic hedges. For an undesignated economic hedge, all changes in the derivative financial instrument’s fair value are recognized currently in revenues.

~~Revenues~~During ~~from real estate developments~~2016, ifAspirity ~~any,~~purchased ~~are~~electricity ~~recognized~~for atsale ~~the~~to ~~time~~retail ofcustomers ~~sale~~in ~~closing~~PJM ifand ~~all~~from ~~significant~~Exelon. ~~conditions~~In ~~are~~2016 ~~satisfied, including~~and ~~adequate down payment~~2015, ~~reasonable~~REH ~~assurance~~acquired ofpower in ~~collectability~~ISO-NE, ~~of any notes received~~PJM, and ~~completion~~from ofcertain other ~~contract requirements.~~wholesale ~~Recognition of all or part of the revenue is deferred if any significant conditions are not satisfied~~suppliers.

~~Costs~~During ~~that~~2016, ~~relate~~the ~~directly~~Company tosold ~~development~~143,071 ~~projects~~MWh ~~are~~purchased ~~capitalized~~for ~~and allocated using the specific identification method. Land acquisition~~$10, ~~improvements~~010, ~~and holding costs~~000, ~~including~~resulting ~~real~~in ~~estate taxes and interest are capitalized while~~ a ~~development~~weighted isaverage incost ~~progress~~of $69.97/MWh, ~~Interest~~down ~~expense,~~from ~~if any~~$26,663,000 isspent ~~capitalized based~~ on ~~specific~~346,037 ~~identification~~MWh ofat ~~notes~~a ~~payable~~cost ~~issued~~of to$77.05/MWh ~~finance~~in ~~specific assets under development~~2015. ~~Once~~The ~~development~~reduction onin acost ~~project has been completed and sales have begun, remaining inventory~~ is ~~recorded~~primarily atdue to the ~~lower~~elimination of ~~cost~~REH orfrom ~~market.~~the ~~Development~~Company’s ~~costs~~consolidated ~~are~~financial ~~charged~~results toafter ~~cost of sales when~~ the ~~related~~first ~~revenue~~quarter isof ~~recognized or when a development is abandoned~~2016.

~~During~~REH ~~2015,~~did ~~the~~not ~~Company~~hedge ~~recorded~~any ~~revenue~~power ofcosts ~~$352,000,~~during ~~cost~~the offiscal ~~sales~~year of ~~$319~~2016,~~000,~~ ~~and~~but ~~capitalized~~during $12015,~~891,800~~ it hedged the cost of ~~costs~~144,667 ~~associated~~MWh ~~with~~or 42% of the ~~its~~electricity ~~real~~sold ~~estate~~to ~~development~~retail ~~activities~~customers. ~~During~~For ~~2014~~the 2015 period, ~~the~~these ~~Company~~designated ~~recorded~~hedges nohad ~~revenue~~the oreffect of increasing the cost of ~~sales~~retail electricity ~~and~~sold ~~capitalized~~by $~~489~~1,713,000 ~~of costs~~.

4331

~~Private~~Sales, ~~Investments~~marketing, and customer service costs: Retail sales and marketing costs and expenses include offline and online marketing costs related to retail customer acquisition and retention. Major offline marketing channels may include out-bound telemarketing, direct mail, door-to-door, mass media (radio, television, print, and outdoor), and affiliates. Online marketing channels may include paid search, affiliates, comparison shopping engines, banner or display advertising, search engine optimization, and e-mail marketing. Customer service costs include all variable costs associated with serving customers such as software, mailing, data aggregation, and reporting.

~~Interest~~During ~~income~~2016 onand ~~securities~~2015, iswe ~~recorded~~spent in$5,038,000 ~~other~~and ~~income~~$1,333,000, respectively on sales and ~~fair~~marketing, ~~value~~with isthe ~~reported~~increase ondriven primarily by Aspirity’s entry into new markets and initiatives to establish the ~~balance~~brand ~~sheet~~of the Company. ~~Securities~~REH ~~are~~utilized ~~reviewed~~minimal ~~for~~marketing ~~possible~~to ~~impairment~~gain atnew ~~least~~customers ~~quarterly~~in 2015. Also included in the 2016 amount is $1,289,000 orspent ~~more~~on ~~frequently~~customer ifservice; ~~circumstances~~whereas ~~arise~~no ~~which~~money was ~~may~~spent ~~indicate~~on ~~impairment~~customer service in 2015.

~~Revenues~~General ~~from~~and administrative ~~services~~expenses: Other general and administrative expenses include salaries, ~~software~~wages, ~~licenses~~incentive compensation, and related costs such as employee benefits and payroll taxes, legal fees and expenses, audit fees, tax compliance reporting service fees, other fees paid for outside consulting services, ~~are~~expenses ~~recognized~~associated onwith amarketing ~~monthly~~our ~~basis~~Notes insuch ~~accordance~~as ~~with~~advertising, printing, ~~the~~and ~~respective~~servicing ~~agreements~~costs ~~with~~as ~~third~~well ~~parties.~~as ~~Revenue~~items ~~from~~such ~~construction~~as ~~services~~trading istools ~~accounted~~and ~~for~~subscriptions, ~~using~~rent, ~~the~~depreciation ~~percentage~~and ofamortization, ~~completion~~insurance, ~~method~~travel, and all other indirect support expenses.

~~During~~For ~~2015~~2016, ~~the~~general ~~Company~~and ~~earned~~administrative expenses decreased by $~~710~~1,841,000 ofto ~~management~~$6,831,000 ~~services~~compared ~~revenue~~to ~~and reported~~ $28,~~286~~672,000 offor ~~construction~~2015, primarily ~~services~~due ~~revenue.~~to ~~During 2014,~~expenses ~~the~~associated ~~Company~~with ~~recorded~~REH nosuch ~~management~~as ortrading ~~construction~~tools ~~services~~and ~~revenue~~subscriptions in association with their hedging activities.

~~Costs~~Other ofincome ~~retail electricity sold~~(expense): ~~REH’s~~In ~~costs~~2016, ofwe ~~electricity~~recorded ~~sold~~net ~~include~~other ~~the~~expense ~~cost~~ of ~~purchased power~~$4, ~~EDC service fees~~558, ~~renewable~~000 ~~energy~~compared ~~certificates,~~to ~~bad~~net ~~debt~~other expense, ~~and gains net~~ of ~~losses and commissions on derivative contracts used to hedge~~$2,303,000 ~~power~~in ~~purchase costs~~2015. ~~Cost~~As ~~of sales does not include~~ the ~~net~~principal ~~gain~~component orof ~~loss~~other onexpense, ~~the~~interest ~~economic~~expense ~~hedges~~increased ~~described~~by ~~above.~~$1,859,000 ~~During~~to ~~2015~~$4, we328,000 ~~purchased electricity~~ for the ~~sale~~year ~~to retail customers in ISO-NE’s and PJM’s wholesale markets and~~ from ~~certain~~$2,468,000 ~~other wholesale~~during ~~suppliers.~~2015, Weprimarily ~~are~~due ~~typically required~~ to ~~maintain~~an ~~cash~~increase ~~deposits~~ in ~~separate~~outstanding ~~accounts~~debt toas ~~meet~~well ~~our~~as ~~wholesale~~a ~~energy~~higher ~~vendors’ financial~~weighted ~~assurance~~average ~~requirements~~interest rate ~~to purchase energy, ancillary services, and capacity which amount is included~~ in ~~“cash in trading accounts”~~2016.

~~During~~Discontinued ~~2015,~~operations: ~~REH~~In ~~hedged~~ the ~~cost~~first quarter of ~~144~~2016,~~667~~ ~~MWh~~the orCompany ~~41.8%~~moved oftwo ~~the~~segments, ~~346~~diversified investments and wholesale trading,~~037~~ into ~~MWh~~discontinued ofoperations. ~~electricity~~Both ~~sold~~segments toare ~~our~~owned ~~retail~~and ~~customers~~operated by Enterprises. ~~For~~Discontinued ~~the~~operations ~~year~~contributed $712,000 ~~our~~of ~~hedges~~income ~~had~~to the ~~effect~~net loss of ~~increasing~~the Company for the ~~cost~~first ofthree ~~retail~~months ~~electricity~~of ~~sold~~2016, bycompared to $14,~~713~~100,000 of income for the full year of 2015. This is primarily due to the profitable year for wholesale trading in 2015.

~~During~~Preferred ~~2014,~~distributions: ~~REH~~During ~~hedged~~both ~~the~~2016 ~~cost~~and ~~of 76~~2015,~~915~~ ~~MWh~~we ordistributed ~~68% of the 112~~$549,~~378~~000 ~~MWh of electricity sold~~ to our ~~retail~~preferred ~~customers.~~unit ~~For the year, our hedges had the effect of decreasing the cost of retail electricity sold by $92,000~~holder.

In total, during 2015 and 2014, we recorded costs of retail electricity sold of $26,663,000 and $11,441,000, respectively, resulting in gross profits of $3,820,000 and a loss of $ (211,000) in 2015 and 2014, respectively. 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 11.3% in 2015 and 12.6% for 2014.

As shown by the Open Derivative Contracts table on page 44, as of December 31, 2015, we had no designated electricity futures contracts as hedges against the cost of expected 2016 electricity purchases. As of December 31, 2014, 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 was reclassified to cost of retail electricity sold by December 31, 2015.

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 2015 and 2014, we spent $1,353,000 and $325,000, respectively on retail sales and marketing, principally on outbound telemarketing in connection with the TSEE brand.

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 2015, salaries, bonuses, and related costs decreased by $8,254,000 or 38.0% to $13,468,000 compared to $21,722,000 for 2014. Our personnel expense is directly related to the revenue we record, since trader compensation is tied to revenue production, and this increase 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 2015, professional fees decreased by $24,000 or 1.0% to $2,463,000 compared to $2,487,000 in 2014. In 2015, while the Company no longer incurred substantial legal fees in connection with the FERC investigation, it continued to pursue the Canadian former employee litigation. In addition, legal fees were incurred in connection with the Restructuring.

Other general and administrative: Other general and administrative expenses include expenses associated with marketing our Notes such as advertising, printing, and servicing expenses as well as items such as rent, depreciation and amortization, insurance, travel, outside retail customer service costs, and all other direct office support expenses.

For 2015, these costs decreased by $868,000 to $5,226,000 compared to $6,094,000 for 2014. The decrease was primarily related to elimination of the $2,500,000 civil penalty resulting from the FERC settlement, partially offset by increases in public company costs of $797,000, and expenses associated with the Noble acquisition $141,000.

Trading tools and subscriptions: Trading tools and subscriptions consist primarily of amounts paid for services that provide weather reports and forecasting, electrical load forecasting, congestion analysis and other factors relative to electricity production and consumption.

For the year ended December 31, 2015, trading tools and subscriptions expense decreased by $40,000 or 3.0% to $1,293,000 compared to $1,333,000 for 2014, primarily due to the sale of TCP and SUM and fewer traders.

Other income (expense): In 2015, we recorded net other expense of $444,000 compared to net other expense of $2,661,000 in 2014.

For 2015, other income included $1,343,000 of gain on sale of TCP, (recognized as cash principal payments are received on the seller note owed by Angell), $829,000 of interest income, $356,000 of gain on foreign currency exchange and $1,843,000 of other income consisting primarily of revenue associated with the sale of a DataLive software licenses of $1,600,000.

As the principal component of other expense, interest expense increased by $1,276,000 to $3,569,000 for the year from $2,293,000 during 2014, primarily due to an increase of $8,342,000 in outstanding debt from $19,288,000 at December 31, 2014 to $27,630,000 at December 31, 2015.

Provision for taxes: The tax provision of ($47,000) is a tax benefit associated with the acquisition of Noble.

Preferred distributions: During both 2015 and 2014, we distributed $549,000 to our preferred unit holder.

Liquidity, Capital Resources, and Cash Flow

InThe ~~order~~accompanying toconsolidated ~~participate~~financial instatements ~~the~~have ~~wholesale~~been ~~trading~~prepared ~~business,~~assuming the ~~pledge~~Company ofwill ~~cash~~continue ~~collateral~~as toa ~~market~~going ~~operators~~concern. ~~such~~However, the asCompany ~~ISOs~~has ~~and~~determined ~~exchanges is~~that ~~required~~due to ~~permit~~the ~~trading~~nature ~~and~~of ~~revenue~~the ~~generation.~~Notes, ~~With~~the ~~respect~~amount toof ~~REH’s~~Note ~~retail~~maturities ~~energy business,~~ in ~~addition~~the to12 ~~collateral posted~~months ~~with~~after ~~ISOs that provides for~~ the ~~acquisition~~ issuance of ~~power~~these ~~for~~financial ~~resale to customers~~statements, ~~it is also required to fund accounts receivable~~ as well as ~~margin~~negative ~~requirements~~financial ~~associated~~trends ~~with~~raises ~~hedges.~~substantial ~~ISOs~~doubt ~~generally~~about ~~require~~its ~~payment~~ability ~~for power every 4 days or so, while the average collection period on receivables is 40~~ to 45continue ~~days. As such, historically, the Company’s capital was largely invested~~as ina ~~trading~~going ~~accounts deposits and receivables~~concern. ~~Capital~~See ~~expenditure~~“Note ~~requirements~~1 ~~are~~– ~~nominal,~~Organization ~~being limited largely to computer~~ and ~~office~~Description ~~equipment, software, and office furniture. Therefore, in any given reporting period, the amount~~ of ~~cash~~Business” ~~consumed~~for ~~or generated~~further ~~was primarily be due to changes in working capital~~discussion.

~~Historically,~~Aspirity ~~capital~~Energy ~~requirements~~and ~~have~~Aspirity ~~been~~Financial ~~funded~~are bystart-up ~~cash~~companies ~~flow~~in ~~positive~~the ~~operations~~retail energy and ~~additional~~financial ~~financing~~services industries, ~~principally~~respectively. inWhile revenues from Aspirity Energy are expected to continue to increase throughout the ~~form~~remainder of the ~~Notes.~~ ~~Should~~year ~~sustained~~as ~~significant~~customers ~~negative~~are ~~cash~~signed up, ~~flow~~overall ~~from~~we ~~operations~~do ~~occur~~not orexpect ~~additional~~such ~~Note~~to ~~sales~~be ~~not~~significant ~~materialize~~until 2017. Further, wethe ~~may be~~Company ~~forced~~does not expect to ~~cover~~report ~~net~~positive cash ~~outflows~~flow from byoperations ~~reducing~~or ~~trading~~profitability ~~account~~on ~~balances~~a ~~and~~regular ~~such~~basis ~~events~~until ~~might~~the ~~have~~first ahalf ~~detrimental~~of ~~effect~~2018 onat the ~~Company~~ earliest.

The ~~following~~Company ~~table~~has isfinanced ~~presented~~its asoperations to date principally through cash on hand, Note sales, and Term Loan receipts. For the year ended December 31, 2016, the Company on a ~~measure~~consolidated ofbasis ~~our~~reported ~~liquidity~~a net loss of $12,893,000 and ~~capital~~cash ~~resources~~used asfor operations of $11,064,000. As of December 31, 2016, the ~~dates~~Company ~~indicated:~~had unrestricted cash, negative working capital, and total members’ deficit of $1,300,000, $14,338,000, and $31,298,000, respectively.

	At December 31,
Dollars in thousands; may not add due to rounding	2015						2014						Increase (decrease)
	Dollars			Percent of total assets			Dollars			Percent of total assets			Dollars			Percent
Liquidity
Unrestricted cash	$	2,331			8.0	%	$	2,397			7.5	%	$	(66	)		-2.7	%
Cash in trading accounts		8,047			27.8	%		21,100			66.4	%		(13,052	)		-61.9	%
Cash collateral		246			0.8	%		-			0.0	%		246			na
Marketable securities		-			0.0	%		312			1.0	%		(312	)		-100.0	%
Trade accounts receivable		5,888			20.3	%		2,394			7.5	%		3,494			145.9	%
Total liquid assets		16,513			56.9	%		26,203			82.5	%		(9,690	)		-37.0	%
Total assets	$	28,999			100.0	%	$	31,770			100.0	%		(2,771	)		-8.7	%
Capital Resources
Current debt	$	13,023			44.9	%	$	8,652			27.2	%	$	4,371			50.5	%
Long term debt		14,607			50.4	%		10,636			33.5	%		3,971			37.3	%
Total debt		27,630			95.3	%		19,288			60.7	%		8,342			43.2	%
Preferred equity		2,745			9.5	%		2,745			8.6	%		-			0.0	%
Common equity		(1,647	)		-5.7	%		(194	)		-0.6	%		(1,453	)		749.0	%
AOCI		-			0.0	%		147			0.5	%		(147	)		-100.0	%
Total members’ equity		1,098			3.8	%		2,698			8.5	%		(1,600	)		-59.3	%
Non-controlling interest		(9,808	)		-33.8	%		-			0.0	%		(9,808	)		na
Total equity		(8,710	)		-30.0	%		2,698			8.5	%		(11,408	)		-422.8	%
Total capitalization	$	18,921			65.2	%	$	21,986			69.2	%	$	(3,065	)		-13.9	%

46Prior to the time that Aspirity Energy is generating sustained positive cash flow from operations and profits, the Company will rely on the timely payment of the Term Loan and its ability to sell Notes to fund Note redemptions and operations. Enterprises’ ability to make timely payments on the Term Loan depends in part on the operations of its Legacy Businesses which were unprofitable in 2016. In the event amounts owed to us are paid late or not paid, our ability to fund operations, sell new Notes, renew existing Notes, and redeem existing Notes will be negatively impacted.

WeHistorically, ~~are~~sales ~~taxed~~and asrenewals aof ~~partnership~~Notes ~~for~~have ~~income~~exceeded ~~tax~~redemptions, ~~purposes~~although ~~which~~there ~~means~~can ~~that~~be weno doassurance ~~not~~that ~~pay~~such ~~any~~will ~~income~~be ~~taxes.~~the ~~Our~~case ~~income~~in ~~or loss for each year is allocated among holders of our common units who are then personally responsible for~~ the ~~tax liability associated with~~future. ~~such~~If ~~income.~~redemptions ~~Our~~exceed ~~Operating Agreement provides for distributions of~~ cash tofrom ~~members~~operations, ~~based~~Term ~~upon~~Loan ~~their~~payments, ~~respective~~renewals, ~~ownership~~and ~~interests in~~new ~~the~~Note ~~amount~~sales, ~~necessary~~then ~~to permit~~ the ~~member~~Company ~~who~~will isneed ~~in the highest income tax bracket to pay all state and federal taxes on our~~additional ~~net~~financing ~~income~~from ~~allocated~~other ~~to such member~~sources.

Given the amount of Notes that are maturing in the 12 months following issuance, the Company has substantial doubt about its ability to continue as a going concern and is unable to conclude that it is probable that management’s plans will be able to mitigate adverse conditions.

Term Loan Amendment

On July 1, 2015, as part of the Restructuring, Aspirity Financial entered into a Term Loan with Enterprises, pursuant to which the Company agreed to loan Enterprises an aggregate principal amount of $22,206,000 with a weighted average interest rate of 14.08% and a maturity date of December 30, 2019. Up until October 31, 2016, the cash flow required to service the Term Loan Notes (those that were outstanding as of June 30, 2015, including any renewals thereof) was directly tied to the monthly invoices sent by the Company to Enterprises.

On November 1, 2016, the Company and Enterprises executed Amendment No. 3 to the Term Loan Agreement. Among other things, the Amendment revises certain definitions and incorporates a new amortization schedule calling for fixed monthly payments of principal and interest at a fixed annual rate of 15.12% with a balloon payment on the maturity date. The principal amount of the loan was adjusted up to $18,238,000 to include $1,592,000 of accrued interest income and costs that were capitalized.

The Amendment also revises the accounting treatment of the mandatory prepayments owed the Company as the result of the sale by Enterprises of REH, which closed on November 2, 2016, and further provides for certain additional optional prepayments. Pursuant to the Amendment, both the mandatory prepayments due to the REH sale and the optional prepayments provided for in the Amendment are treated as “prepayments of installments” rather than as “prepayments of principal”.

On November 4, 2016, the Company received $2,008,000, consisting of $1,508,000 of mandatory and $500,000 of optional prepayments. The Amendment also specifies the conditions under which the Company will release its security interest in the equity interests of Enterprises and provides for adjustments to certain of the covenants and agreements of the borrower with respect to monthly reporting, minimum liquidity, permitted liens, and defaults.

The Amendment also provides that Mr. Krieger, the Company’s Chairman and controlling shareholder, will assist Aspirity Energy in obtaining certain surety bonds required by its geographic expansion plans and provides that the Company and its subsidiaries have no explicit obligation to lend funds to the Borrower, Mr. Krieger, or their affiliates, but that any such request will be considered based on the facts and circumstances existing at the time.

In conjunction with the modifications in Amendment 3, management evaluated the classification of the Term Loan. Its terms are consistent with those likely available from a third party and there is intention to repay. While the loan is not in default, due to recent losses, the historical volatility of its primary business of wholesale electricity trading, and the level of assets in the business, there is no longer significant evidence of collectability of all amounts owed.

Therefore, effective with the date of the amendment, the Term Loan is classified on the balance sheet as a receivable from a related party, a contra-equity account. Subsequent to November 1, 2016, the cost recovery method will be used account for income related to the Term loan. All payments received after the amendment were recognized as equity contributions and reductions to the principal of the loan. Under this method, cash receipts are first applied to reduce the principal balance of the receivable and second to income after all principal has been repaid.

The following table is presented as a measure of our liquidity and capital resources as of the dates indicated, including “Total liquid assets”, which is a non-GAAP measure :

	At December 31,
	2016						2015						Increase (decrease)
Dollars in thousands; may not add due to rounding	Dollars			Percent of total assets			Dollars			Percent of total assets			Dollars			Percent

Liquidity
Unrestricted cash	$	1,300			58.8	%	$	1,371			4.8	%	$	(71	)		-5.2	%
Restricted cash		220			9.9	%		-			0.0	%		220			na
Cash in trading accounts		-			0.0	%		1,800			6.3	%		(1,800	)		-100.0	%
Cash in collateral accounts		25			1.1	%		246			0.9	%		(221	)		-89.8	%
Accounts receivable		503			22.7	%		3,558			12.4	%		(3,055	)		-85.9	%

Total liquid assets		2,047			92.6	%		6,975			24.3	%		(4,929	)		-70.6	%

Prepaid expenses and other assets		87			3.9	%		82			0.3	%		5			5.9	%
Assets of discontinued operations - current		-			0.0	%		11,084			38.6	%		(11,084	)		-100.0	%

Total current assets		2,134			96.5	%		18,142			63.2	%		(16,007	)		-88.2	%

Other assets		77			3.5	%		10,544			36.8	%		(10,467	)		-99.3	%

Total assets	$	2,212			100.0	%	$	28,685			100.0	%		(26,474	)		-92.3	%

Capital Resources
Current debt	$	12,430			562.1	%	$	11,333			39.5	%	$	1,097			9.7	%
Long term debt		17,037			770.4	%		14,050			49.0	%		2,987			21.3	%

Total debt		29,467			1332.4	%		25,383			88.5	%		4,084			16.1	%

Preferred equity		2,745			124.1	%		2,745			9.6	%		-			0.0	%
Term Loan receivable from related party		(15,067	)		-681.3	%		-			0.0	%		(15,067	)		na
Common equity		(18,977	)		-858.1	%		(7,500	)		-26.1	%		(11,477	)		153.0	%
Non-controlling interest		-			0.0	%		(3,296	)		-11.5	%		3,296			-100.0	%

Total equity		(31,298	)		-1415.2	%		(8,051	)		-28.1	%		(23,248	)		288.8	%

Total capitalization	$	(1,831	)		-82.8	%	$	17,332			60.4	%	$	(19,164	)		-110.6	%

For income tax purposes, we are taxed as a partnership which means that we do not pay any income taxes. 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 Operating Agreement provides for distributions of cash to members based upon their respective ownership interests in the amount necessary to permit the member who is in the highest income tax bracket to pay all state and federal taxes on our net income allocated to such member.

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

While we believe that payments from Enterprises on the Term Loan, anticipated cash generated from operating activities, availability of trade credit with respect to power purchases, and anticipated proceeds from our Notes Offering will be sufficient to meet ~~our~~ operating cash requirements and obligations under the Notes ~~and Term Loan Notes~~ for the next twelve months, there can be no assurance that this will prove to be the case. Further, given the nature of our Notes and the amount of maturities in the 12 months following issuance, the Company has substantial doubt about its ability to continue as a going concern.

~~Consequently,~~The weCompany regularly ~~evaluate~~evaluates ~~other~~ sources of debt financing inother ~~addition~~than to the Notes and ~~we are currently considering seeking~~ additional equity capital ~~in order~~ to ~~provide~~meet ~~added~~its ~~flexibility~~funding ~~to support our anticipated growth and working capital~~ needs. However, there can be no assurance that these efforts will prove to be successful.

The table below summarizes our primary sources and uses of cash for the years ended December 31, ~~2015~~2016 and ~~2014~~2015 as derived from the statements of cash flows included in this Form 10-K.

Dollars in thousands; may not add due to rounding	For the Years Ended December 31,
Dollars in thousands;	For the Years Ended December 31,
							Increase (decrease)
may not add due to rounding							Increase (decrease)
	2015			2014			Dollars			Percent
	2016			2015			Dollars			Percent
Net cash provided by (used in)
Operating activities	$	1(11,~~089~~064	)	$	54(5,884	)	$	1(5,~~035~~179	)		~~1922~~88.60	%
Investing activities		(23,~~538~~153	)		(~~3,515~~59	)		~~977~~3,212			-275477.84	%
Financing activities		17,~~171~~992			34,~~009~~847			(13,~~838~~145	)		~~-61~~64.19	%
Net cash flow		(278	)		(452	)		174			-38.5	%
Net cash flow, continuing operations		81			(1,096	)		1,178			7.4	%
Effect of exchange rate changes on cash		212			(341	)		553			61.8	%
Net cash flow, discontinued operations		481			819			(338	)		-41.2	%
Unrestricted cash
Net cash flow		562			(278	)		840			202.4	%
Beginning of period		2,397			3,190			(793	)		-24.9	%
Effect of exchange rate changes on cash		87			212			(125	)		-58.9	%
End of period	$	2,331		$	2,398		$	(66	)		-2.7	%
Unrestricted cash and restricted cash
Beginning of period		2,331			2,397			(66	)		-2.7	%
Adjustment for deconsolidation		(1,461	)		-			(1,461	)		na
End of period	$	1,520		$	2,331		$	(812	)		-34.8	%

47Continuing operations for year ended December 31, 2016 used $11,064,000 of cash for operating activities. The largest uses were the net loss of $12,894,000, while the largest source of cash was an increase in accrued interest of $752,000. The net loss for the period was primarily driven by customer acquisition costs of $3,407,000, general and administrative expenses of $6,831,000 and interest expense of $4,328,000. During 2016, we generated $3,153,000 of cash from investing activities, principally due to proceeds from the Term Loan, and $7,992,000 of cash from financing activity, principally due to sales of Notes, net of redemptions, and partially offset by distributions of $549,000 paid to the holder of our preferred units. Overall, for 2016, net cash flow provided by continuing operations totaled $81,000 and net cash flow provided by discontinued operations was $481,000. At December 31, 2016, our unrestricted and restricted cash totaled $1,300,000 and $220,000, respectively, and our debt totaled $29,467,000 compared to $25,383,000 as of as of December 31, 2015.

For the year ended December 31, 2015, we generated $1,144,000 from operating activities. The largest source of cash from operations was a $7,910,000 reduction in deposits in trading and collateral accounts, while the largest single use was the payment of accrued compensation of $3,614,000. During 2015, we used $2,538,000 of cash for investing activities, principally an increase in real estate held for investment of $1,892,000. At December 31, 2015, our debt totaled $27,630,000 compared to $19,288,000 as of the prior year end. For the year, the Company generated $1,116,000 from financing activities, including a net $7,916,000 increase in debt and payment of $6,499,000 in distributions. Of the total distribution amount, $549,000 was paid to the holder of our preferred units and $5,950,000 was paid to our common unit-holders.35

~~For~~Continuing operations for the year ended December 31, ~~2014,~~2015 weused ~~generated~~ $545,884,000 ~~from~~of cash for operating activities. The largest ~~source~~uses ~~of cash from operations was~~were the net ~~income~~loss of $34,~~779~~762,000 ~~which~~and ~~included~~an aincrease ~~non-cash~~in ~~charge~~accounts receivable of $31,~~607~~680,000, ~~related~~while to the ~~FERC~~largest ~~settlement,~~sources ~~and~~of ~~the~~cash ~~most significant~~were ~~use~~increases ~~was~~in aaccounts payable of $101,~~528~~412,000 ~~increase~~and inaccrued ~~cash~~expenses inof ~~trading accounts due to increased collateral requirements for both our wholesale and retail businesses~~$1,745,000. During ~~2014~~2015, we used $359,~~530,~~000 of cash for investing activities, ~~the~~and ~~most~~generated ~~significant~~$4,847,000 of ~~which~~cash ~~was~~from ~~the~~financing ~~purchase of~~activity, ~~Ultra~~principally ~~Green’s~~due ~~convertible~~to ~~notes~~sales ~~for~~of $1Notes net of redemptions,~~605,000.~~ Atwhich ~~December~~was ~~31,~~partially ~~2014,~~offset ~~our~~by ~~debt~~common ~~totaled~~distributions of $191,~~288~~251,000 ~~compared~~and topreferred distributions of $10549,~~185,~~000 paid asto of the ~~prior~~holder ~~year~~of ~~end.~~our ~~For~~preferred ~~the~~units. ~~year~~Overall, ~~the~~for ~~Company~~2015, ~~generated~~net ~~$3,009,000~~cash ~~from~~flow ~~financing~~used ~~activities,~~in ~~including~~continuing aoperations ~~net~~totaled $91,~~103~~096,000, ~~increase~~while incash ~~debt~~flow ~~and~~from ~~payment~~discontinued ofoperations provided $5819,~~276,~~000. inAt ~~distributions.~~December Of31, ~~the~~2015, ~~total~~our ~~distribution~~cash ~~amount,~~totaled $~~549~~2,331,000 ~~was~~and ~~paid~~our debt tofrom ~~the~~continuing ~~holder of~~operations ~~our~~totaled ~~preferred~~$25,383,000 ~~units~~compared ~~and~~to $419,~~727~~288,000 ~~was~~as ~~paid~~of toas ~~our~~of ~~common~~December ~~unit-holders~~31, 2014.

Financing

~~RBC Line of Credit~~Exelon

On ~~May~~March 1230, ~~2014~~2016, ~~the~~we ~~Company~~entered ~~drew~~into ~~$700,000~~a ~~under~~full anrequirements ~~evergreen,~~preferred ~~uncommitted~~supply ~~line~~agreement ofwith ~~credit~~Exelon ~~from~~to ~~Royal~~provide ~~Bank~~us ofwith ~~Canada~~all (the ~~“RBC Line”~~power and ~~“RBC”, respectively). Advances under the RBC Line bear interest at a variable annual interest rate~~ ofancillary 1services ~~month~~we ~~LIBOR~~need ~~plus~~to ~~2.25%~~serve ~~set~~our atcustomers ~~the time of advance~~ for aan 30initial ~~day~~ term, ~~mature~~expiring aton ~~various~~March ~~dates~~30, ~~and are collateralized by assets held in the Company’s marketable securities account~~2019. 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.

AsUnder the terms of ~~December~~the 31PSA, ~~2015~~on a daily or weekly basis as we request, ~~the~~Exelon ~~Company~~will ~~had~~provide nofirm, ~~marketable~~fixed ~~securities~~quotes ~~and~~for nopower ~~borrowings~~for ~~outstanding~~terms ~~under~~from 1 to 36 months out for each of the ~~RBC~~service ~~Line~~areas in which we operate. AsSuch quotes will include all costs of ~~December 31~~energy, ~~2014~~capacity, ancillary ~~the~~services, ~~Company~~and ~~had~~RECs ~~$311~~necessary to meet state minimum renewable energy requirements to serve residential and small commercial customers. In addition,~~586~~ ofExelon ~~marketable~~absorbs ~~securities~~all deviations between forecasted and noactual ~~borrowings~~customer ~~outstanding~~usage. ~~under~~Finally, the ~~RBC~~PSA ~~Line~~provides that Exelon will post any collateral required of us by an ISO or EDC.

~~Exelon~~In addition to eliminating commodity price and volumetric risk, the PSA also incorporates the ability for us to defer payment of all or a portion of Exelon’s invoices to us based on certain criteria as defined in the agreement, including an asset pledge and certain financial covenants. The criteria used to determine the amount of deferral are not limited to, but include the amount of receivables, both billed and unbilled, as well as a portion of the forward value of customer contracts. As of December 31, 2016, we have deferred $907,000 of payments to Exelon.

OnNotes March 29, 2016 we entered into a full requirements preferred supply agreement with Exelon to provide us with all the power and ancillary services we need to serve our customers for an initial term expiring on March 29, 2019.Offering

~~Under~~On ~~the~~May ~~terms~~8, ~~of the PSA~~2015, onwe filed a ~~daily~~new orregistration ~~weekly~~statement ~~basis~~with asrespect weto ~~request,~~the ~~Exelon~~Notes ~~will~~(File ~~provide~~No. ~~firm,~~333-203994) ~~fixed~~to ~~quotes~~continue ~~for~~our ~~power~~Notes ~~for terms from~~Offering ~~one~~under tothe 36Old ~~months~~S-1 ~~out~~until ~~for~~the ~~each~~effective date of the ~~service~~New ~~areas in which we operate~~S-1. ~~Such~~The ~~quotes~~new ~~will~~registration ~~include~~replaces ~~all~~the ~~costs~~original ofstatement ~~energy, capacity, ancillary services,~~ and ~~RECs~~covers ~~necessary~~ up to ~~meet~~$75,000,000 ~~state~~in ~~minimum~~principal ~~renewable~~amount ~~energy~~of ~~requirements~~3-and to6-month ~~serve residential~~ and ~~small~~1, ~~commercial customers.~~2, In3, ~~addition~~4, ~~Exelon~~5, ~~absorbs all deviations between forecasted~~ and ~~actual~~10 ~~customer~~year ~~usage~~Notes. ~~Finally,~~The ~~the~~New ~~PSA~~S-1 ~~provides that~~was ~~Exelon~~declared ~~will~~effective ~~post any collateral required of us~~ by the anSEC ~~ISO~~on orNovember ~~EDC~~12, 2015.

InFor ~~addition~~the toyears ~~eliminating~~ended ~~commodity~~December ~~price~~31, 2016 and ~~volumetric~~2015, ~~risk~~we incurred $2,228,000 ~~the~~and ~~PSA~~$2,081,000, ~~also~~respectively, ~~incorporates~~of ~~the~~offering-related ~~ability~~expenses, including ~~for~~marketing usand tocertain ~~defer~~printing ~~payment~~expenses, ~~of all~~legal orand aaccounting ~~portion~~fees, offiling ~~Exelon’s~~fees, ~~invoices~~and totrustee usfees ~~based~~but onexcluding ~~certain~~amounts capitalized ~~criteria~~as deferred financing costs and amortized as ~~defined~~Notes inare ~~the~~sold. ~~agreement,~~Deferred ~~including~~financing ancost ~~asset~~amortization ~~pledge~~totaled $74,000 and ~~certain~~$229,000 ~~financial~~for ~~covenants~~the years ended December 31, 2016 and 2015, respectively. ~~essentially~~At ~~providing~~December us31, ~~with~~2016, anet ~~revolving~~deferred ~~line~~financing costs ofrelated ~~credit~~to the Notes totaled $465,000.

48From the effective date of May 10, 2012 through December 31, 2016, we issued a total of $63,789,000 of Notes, of which $40,642,000 were initial sales for cash and $23,147,000 were renewals for which we did not receive any additional proceeds, and we redeemed $10,709,000 for a net principal outstanding as of December 31, 2016 of $29,933,000.

~~Continuous Notes Offering and Term Loan~~36

On May 10, 2012, our first Form S-1 registration statement relating to the offer and sale of our Notes (File No. 333-179460) was declared effective by the SEC, and the offering commenced on May 15, 2012. This Old S-1 covered up to $50,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes. On May 8, 2015, we filed a new registration statement with respect to the Notes (File No. 333-203994) to continue our Notes Offering under the Old S-1 until the effective date of the New S-1. The new registration replaces the original statement and covers up to $75,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes. The New S-1 was declared effective by the SEC on November 12, 2015.

For the years ended December 31, 2015 and 2014, we incurred $2,081,000 and $1,284,000, respectively, of offering-related expenses, including marketing and certain printing expenses, legal and accounting fees, filing fees, and trustee fees but excluding amounts capitalized as deferred financing costs and amortized as Notes are sold. For the years ended December 31, 2015 and 2014, deferred financing cost amortization totaled $229,000 and $131,000, respectively. At December 31, 2015, net deferred financing costs related to the Notes totaled $314,000.

From the effective date of May 10, 2012 through December 31, 2015, we issued a total of $45,302,000 of Notes, of which $30,228,000 were initial sales and $15,074,000 were renewals for which we did not receive additional proceeds. As of December 31, 2015, we had $24,485,000 in principal amount of notes outstanding.

On July 1, 2015, as part of the internal reorganization, Aspirity Financial entered into a Term Loan with Enterprises. Pursuant to the Term Loan, the Company agreed to loan Enterprises an aggregate principal amount of $22,205,613, with a weighted average interest rate of 14.08%, and maturity date of December 30, 2019. Cash flow from the Legacy Businesses supports the Term Loan Notes (only those outstanding as of June 30, 2015), including any renewals thereof. Accordingly, and subject to monthly true-ups, the repayment schedule of the Term Loan reflects the maximum possible redemptions of, and the weighted average interest rate paid on, Term Loan Notes in a given month. The equity of Enterprises has been pledged to Aspirity Financial to secure repayment of the Term Loan.

Due to the consolidation of Enterprises as a VIE, the Term Loan is eliminated. See also Notes 2 and 20 to the consolidated financial statements in Item 8.

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~~ with GAAP in the ~~company’~~Company's financial statements.

Non-GAAP financial measures utilized by the Company include presentations of liquidity measures and debt-to-equity ratios. The Company’s management believes that these non-GAAP financial measures provide useful information to investors and enable investors and analysts to more accurately compare the Company’s ongoing financial performance over the periods presented.

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 these non-GAAP financial measures provide useful information to investors and enable investors and analysts to more accurately compare the Company’s ongoing financial performance over the periods presented.

Critical Accounting Policies and Estimates

Variable Interest Entities - Principles of Consolidation

Generally, we consolidate only business enterprises that we control by ownership of a majority voting interest. However, there are situations in which consolidation is required even though the usual condition of consolidation (ownership of a majority voting interest) does not apply. Generally, this occurs when an entity holds an interest in another business enterprise that was achieved through arrangements that do not involve voting interests, which results in a disproportionate relationship between such entity’s voting interests in, and its exposure to the economic risks and potential rewards of, the other business enterprise. This disproportionate relationship results in what is known as a variable interest, and the entity in which we have the variable interest is referred to as a “VIE.”

The Company follows ASC 810-10-15 guidance with respect to accounting for VIEs. A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any of the characteristics of a controlling financial interest. A variable interest is an investment or other interest that will absorb portions of a VIE’s expected losses or receive portions of the entity’s expected residual returns. Variable interests are contractual, ownership, or other pecuniary interests that change with changes in the fair value of the entity’s net assets. A party is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides the party with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of the power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances.

AnThe ~~assessment of the relationship between the~~ Company ~~and~~consolidated Enterprises ~~following~~until ~~the~~March ~~Distribution~~30, ~~was~~2016 ~~performed~~when ~~because~~all ~~Timothy~~Class ~~Krieger is~~B aunits ~~related~~were ~~party~~converted ofinto ~~both~~Class ~~Aspirity~~A ~~and~~units ~~Enterprises,~~due ~~and~~to ~~because~~ the ~~entities have an ongoing business relationship resulting~~FERC ~~from~~approval ~~the Term Loan. Aspirity holds a variable interest in Enterprises in the form~~ of the ~~Term~~change ~~Loan, making Enterprises a VIE. The outstanding balance~~ of ~~the~~control ~~Term Loan (~~and ~~any future amounts that~~ the ~~Company~~amending ~~may~~of ~~lend to Enterprises) represent~~ the ~~Company’s maximum~~Operating ~~exposure to loss from the VIE~~Agreement. ~~Creditors~~This ofconversion ~~Enterprises~~significantly dochanged ~~not have recourse against~~ the ~~general credit~~ nature of the ~~Company, regardless~~relationship ofbetween ~~whether it is accounted for as a consolidated entity. While~~ the Company ~~will include the assets~~ and ~~net income of~~ Enterprises insuch ~~its~~that ~~consolidated financial statements,~~ the Company ~~does~~is ~~not~~no ~~have~~longer ~~rights~~required to ~~those~~consolidate ~~assets other than pursuant to its rights under the Term Loan~~Enterprises.

~~Revenue~~Discontinued ~~Recognition and Commodity Derivative Contracts~~Operations

~~Revenues~~ASU in2014-08 ~~our~~provided ~~wholesale~~an ~~trading~~update ~~business~~to ~~are~~ASC ~~derived~~205 ~~from~~when ~~trading~~determining ~~financial~~if ~~electricity~~a ~~and~~component ~~derivative~~of ~~energy~~a ~~contracts~~business ~~while~~should ~~those~~be accounted for ~~our~~ ~~retail~~as ~~segment~~a ~~result from electricity sales to end-use consumers. In our trading activities~~discontinued operation, ~~contracts~~ with the ~~exchanges on~~primary ~~which~~consideration webeing ~~trade~~whether ~~permit net settlement, including~~ the ~~right~~disposal torepresented ~~offset~~a ~~cash~~strategic ~~collateral~~shift inthat ~~the~~has ~~settlement~~or ~~process.~~will ~~Accordingly, we~~have ~~net~~a ~~cash collateral against the derivative position in the accompanying consolidated balance sheets. All realized and unrealized~~major ~~gains~~effect ~~and losses~~ on ~~derivative~~an ~~instruments~~entity’s ~~are~~operations ~~recorded~~and infinancial ~~revenues~~results. 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.

5037

~~Hedge~~For ~~Accounting~~the Company, each of the three segments of Enterprises was evaluated individually. It was concluded that the results of all three segments have a major effect on the entity’s operations given their size and fact that they are separate reportable segments. However, it was determined that the disposal of wholesale trading and diversified investments would represent a strategic shift for the Company. Therefore, wholesale trading and diversified investments are reported as discontinued operations up to and as of December 31, 2015, while the retail energy services business of REH was accounted for in continuing operations up to and until March 30, 2016. Thereafter, no part of Enterprises’ business is consolidated with the Company.

InTerm ~~our~~Loan ~~retail~~Receivable ~~business,~~from weRelated 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.Party

~~For~~Prior ato ~~cash~~Amendment ~~flow~~3 ~~hedge,~~on ~~the~~November ~~effective~~1, ~~portion~~2016, ~~of any change in~~ the ~~hedging~~Company ~~instrument’s fair value is~~ recorded ~~as other comprehensive income until~~ the ~~change~~Term inLoan ~~value~~receivable ofas ~~the~~an ~~hedged~~asset ~~item~~and isrecorded ~~recognized~~financial inservices revenue ~~earnings. To qualify~~ for ~~hedge~~interest ~~accounting,~~incurred ~~the~~on ~~hedge~~a ~~relationships must~~monthly ~~meet~~basis. ~~extensive~~Any ~~documentation~~portion ~~requirements~~of ~~and~~a ~~hedge~~payment ~~effectiveness~~not ~~and~~related ~~ineffectiveness~~to ~~must~~interest bewas ~~assessed~~applied ~~and~~to ~~measured~~the ~~on an~~principal ~~on-going basis~~balance.

~~Fair~~In ~~Value~~conjunction ~~Measurements~~with the modifications in Amendment 3, management evaluated the classification of the Term Loan. Its terms are consistent with those likely available from a third party and there is intention to repay. While the loan is not in default, due to recent losses, the historical volatility of its primary business of wholesale electricity trading, and the level of assets in the business, there is no longer significant evidence of collectability of all amounts owed.

~~FASB’s~~Therefore, ~~Fair~~effective ~~Value~~with ~~Measurement~~the ~~Topic~~date ~~establishes~~of athe ~~hierarchy~~amendment, ofthe ~~inputs~~Term ~~with~~Loan ~~respect~~is toclassified ~~determining~~on the ~~fair~~balance ~~value~~sheet ofas ~~assets~~a ~~and~~receivable ~~liabilities for~~from ~~financial~~a ~~reporting~~related ~~purposes.~~party, a ~~The~~contra-equity ~~three~~account. ~~types~~Subsequent ofto ~~inputs~~November ~~are “Level~~ 1”, ~~(quoted prices in active markets for identical assets or liabilities)~~2016, ~~“Level~~the 2”cost ~~(inputs~~recovery ~~other~~method ~~than~~will ~~quoted~~be ~~prices~~used ~~that~~account ~~are~~for ~~observable~~income ~~either~~related ~~directly~~to ~~or indirectly~~the ~~for~~Term ~~the~~loan. ~~asset~~All orpayments ~~liability),~~received ~~and~~after ~~“Level~~the 3”amendment ~~(unobservable~~were ~~inputs~~recognized ~~for~~as ~~which~~equity ~~little~~contributions orand noreductions ~~market~~to ~~data~~the ~~exists).~~principal ~~Financial~~of ~~instruments~~the ~~that~~loan. ~~are~~Under ~~not~~this ~~traded~~method, incash ~~publicly~~receipts ~~quoted markets or that~~ are ~~acquired~~first ~~based~~applied onto ~~prices~~reduce ~~and~~the ~~terms~~principal ~~determined~~balance byof ~~direct negotiation with~~ the ~~issuer~~receivable ~~are classified as Level 3~~ and ~~carried~~second atto ~~book~~income after ~~value,~~all ~~which~~principal ~~management~~has ~~believes~~been ~~approximates fair value, until circumstances otherwise dictate~~repaid.

~~With~~Revenue 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.Recognition

~~Real~~Revenue ~~Estate~~from ~~Development~~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.

~~Revenues~~Revenue ~~from~~for ~~real~~financial ~~estate~~services ~~developments,~~pertains ifto ~~any, are recognized at~~ the ~~time~~Term ofLoan ~~sale~~with ~~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~~Enterprises. ~~Recognition~~Revenue ofis ~~all~~recognized oras ~~part~~interest ~~of the revenue~~ is ~~deferred~~incurred ifon ~~any significant conditions are not satisfied. Costs that relate directly to development projects are capitalized and allocated using~~ the ~~specific~~Term ~~identification method~~Loan. ~~Land acquisition,~~ ~~improvements,~~As ~~and~~of ~~holding~~November ~~costs~~1, ~~including real estate taxes and interest are capitalized while a development is in progress. Interest expense~~2016, 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~~Company ~~cost~~will orno ~~market.~~longer ~~Development~~recognize ~~costs~~financial ~~are~~services ~~charged~~revenue tofor ~~cost of sales when~~ the ~~related~~Term ~~revenue is recognized or when a development is abandoned~~Loan.

~~Profits~~Subsequent ~~Interest~~to ~~Payments~~November 1, 2016, the cost recovery method will be used account for income related to the Term Loan. All payments received after the amendment were recognized as equity contributions and reductions to the principal of the loan. Under this method, cash receipts are first applied to reduce the principal balance of the receivable and second to income after all principal has been repaid.

~~One~~Unit ofBased Enterprises’ second-tier subsidiaries, CEF, has Class B members. Under the terms of such subsidiary’s member control agreement, 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 opportunity for 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.Compensation

~~For~~The ~~the~~Company ~~years~~expenses ~~ended~~unit ~~December~~based ~~31,~~awards ~~2015~~pursuant ~~and~~to ~~2014,~~ASC weTopic ~~recorded~~718 ~~$2,478,000~~Compensation-Stock ~~and~~Compensation ~~$6,364,000,~~which ~~respectively,~~requires inthat ~~salaries~~compensation cost ~~and~~at ~~wages~~the ~~and~~grant ~~related~~date fair value of unit-based awards be recognized over the requisite service period. The Company estimates ~~taxes,~~grant ~~representing~~date fair value using a discounted cash flow model as the ~~allocation~~Company’s ofunits ~~profits~~are tonot ~~Class~~publicly Btraded. ~~members~~This model includes highly subjective inputs including cost of capital and growth projections. The ~~amount~~Company ofused ~~accrued~~the ~~profits~~discounted ~~interests~~cash ~~included~~flow inmodel ~~accrued~~due ~~compensation~~to atlimited ~~December~~operations ~~31,~~of ~~2015~~the ~~and~~Company ~~2014~~as ~~was~~well ~~$139,000~~as ~~and~~the ~~$801,000,~~lack ~~respectively~~of publicly trade equity.

5138

Item 7A - Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk in our normal business activities. Market risk is the potential loss that may result from changes associated with an existing or forecasted financial or commodity transaction. The types of market ~~risks~~risk we are exposed to are ~~commodity price risk,~~ interest rate risk, liquidity risk, ~~credit risk~~ and ~~currency~~credit ~~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~~One ~~price~~of the largest risks ~~result~~that ~~from~~a ~~exposures~~retail toelectricity ~~changes~~provider infaces ~~spot~~is ~~prices,~~commodity ~~forward~~risk ~~prices,~~from ~~volatilities,~~fluctuating ~~and~~energy ~~correlations~~prices. ~~between~~The ~~various~~Company ~~commodities,~~has ~~such~~mitigated asthis ~~natural~~risk ~~gas,~~by entering into the PSA with Exelon. The PSA agreement is a full requirements contract which means that Exelon provides electricity, ~~coal,~~at ~~oil,~~a ~~and~~stated ~~emissions~~price ~~credits~~that will not change for the duration of the customer’s contract. This allows the Company to avoid risk from fluctuating prices in the energy market.

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. There were no FTR positions as of December 31, 2015. As a result of this liquidity assumption, the VaR of our FTRs may not be added to that of our other positions.

The following table summarizes our liquid and illiquid VaR as of and for the years ended December 31, 2015, and 2014:

							Increase (decrease)
	2015			2014			Units			Percent
Liquid VaR
As of December 31	$	35,876		$	164,772		$	(128,896	)		-78.2	%
For the year ended December 31:
Average	$	270,611		$	384,094		$	(113,483	)		-29.5	%
Maximum		1,041,045			1,470,187			(429,142	)		-29.2	%
Minimum		15,220			7,453			7,767			104.2	%
VaR, pct of cash in trading accounts
As of December 31		0.45	%		2.53	%		-2.08	%		-82.4	%
For the year ended December 31:
Average (1)		1.86	%		2.07	%		-0.21	%		-10.3	%
Maximum (1)		7.14	%		9.57	%		-2.43	%		-25.4	%
Minimum (1)		0.10	%		5.00	%		-4.90	%		-97.9	%
Illiquid VaR
As of December 31	$	-		$	3,951,414		$	(3,951,414	)		-100.0	%
For the year ended December 31:
Average	$	-			na			na			na
Maximum		-			na			na			na
Minimum		-			na			na			na
VaR, pct of cash in trading accounts
As of December 31		na			18.73	%		-18.73	%		-100.0	%
For the year ended December 31:
Average (1)		na			na			na			na
Maximum (1)		na			na			na			na
Minimum (1)		na			na			na			na

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

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

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

Percentage change in		Average percentage change in mark-to-market valuation (1)							Dollar change in mark-to-market valuation (1)
forward price from December 31, 2015		Derivatives held for trading			Economic hedges			Cash flow hedges	Derivatives held for trading			Economic hedges			Cash flow hedges
10	%		47.0	%		202.7	%	na		67,080			91,289		na
5	%		23.5	%		101.4	%	na		33,540			45,645		na
1	%		4.7	%		20.3	%	na		6,708			9,129		na
-1	%		-4.7	%		-20.3	%	na		(6,708	)		(9,129	)	na
-5	%		-23.5	%		-101.4	%	na		(33,540	)		(45,645	)	na
-10	%		-47.0	%		-202.7	%	na		(67,080	)		(91,289	)	na

1 - Table includes only liquid positions

Interest Rate Risk

As of December 31, ~~2015~~2016 and ~~2014~~2015, we had $~~3,101,000~~0 and $13,~~635~~101,000 of variable rate debt outstanding. The interest rates charged on such are based in part on changes in certain market indices plus a credit margin, but are subject to “floors”, which may have the effect of converting variable rates to fixed rates and such was the case at December 31, 2015 ~~and 2014~~. Consequently, at ~~either~~December 31, ~~date~~2016, 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~~contracts 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~~considering ~~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 $317,000 and $1,448,680 as of December 31, 2015 and 2014, respectively. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of the dates indicated.

Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations.

In our ~~wholesale~~retail ~~trading~~ business, we ~~monitor~~may ~~and~~be ~~manage~~exposed to certain customer credit ~~risk~~risks. ~~Given~~Although ~~the~~we ~~credit~~are ~~quality,~~currently ~~diversification,~~not ~~and~~exposed ~~term~~to ofretail ~~the~~customer ~~exposure~~credit risk to a large degree due to our participation in ~~the~~POR ~~portfolio~~programs, we doexpect ~~not~~that ~~anticipate~~this asituation ~~material~~will ~~impact~~change onas ~~financial~~we ~~position~~grow orour retail ~~results~~business ofand ~~operations~~expand ~~from~~into ~~nonperformance by~~non-POR ~~any counterparty~~areas.

In our ~~retail~~financial services business, we ~~may be exposed to certain customer credit risks. Although we~~ are ~~currently not~~ exposed to ~~retail~~the ~~customer~~ credit risk torepresented aby ~~large~~the ~~degree~~Enterprises ~~due~~Term ~~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~~Loan. ~~Furthermore,~~The ~~economic~~agreement ~~and market conditions may affect our customers’ willingness~~governing ~~and~~the ~~ability~~loan toincludes ~~pay~~certain ~~their~~provisions ~~bills in a timely manner, which could lead to an increase in bad debt expense above~~ and ~~beyond~~covenants ~~the~~that ~~allowance for~~allow ~~uncollectible accounts charged to~~ us ~~by utilities. In general, we intend~~ to ~~manage~~monitor ~~retail~~this ~~credit~~ risk ~~as described in “Item 1 - Business – Retail Energy Services – Credit Risk Management”~~monthly.

~~Foreign~~Furthermore, ~~Exchange~~economic ~~Risk~~and market conditions may affect the willingness and ability of our retail customers and Enterprises 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 and any bad debt provision we may make directly.

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.39

Item 8 – Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Members

Aspirity Holdings LLC and Subsidiaries

Minneapolis, Minnesota

We have audited the accompanying consolidated balance ~~sheets~~sheet of Aspirity Holdings, LLC and ~~Subsidiaries~~subsidiaries (the “Company”) as of December 31, ~~2015 and 2014~~2016, and the related consolidated statements of comprehensive ~~income~~loss, changes in members’ ~~equity~~deficit, and cash flows for the ~~years~~year ~~then~~ ended December 31, 2016. These ~~consolidated~~ financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these ~~consolidated~~ financial statements based on our ~~audits~~audit.

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

In our opinion, ~~the~~such consolidated financial statements ~~referred to above~~ present fairly, in all material respects, the financial position of ~~Aspirity~~the ~~Holdings LLC and Subsidiaries~~ Company as of December 31, ~~2015 and 2014~~2016, and the results of ~~their~~its operations and its cash flows for the ~~years~~year ~~then~~ ended December 31, 2016, in conformity with ~~U.S.~~accounting principles generally accepted ~~accounting~~in ~~principles~~the United States of America.

~~/S/~~The accompanying ~~BAKER~~consolidated ~~TILLY~~financial ~~VIRCHOW~~statements ~~KRAUSE~~for the year ended December 31, ~~LLP~~2016 ~~Minneapolis~~have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, ~~Minnesota~~the ~~April~~Company’s 15recurring losses from operations, ~~2016~~members’ deficit, and lack of sufficient cash flows to meet its obligations, including repayment of renewable unsecured subordinated notes, and sustain its operations raise substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 1 to the financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

56/s/ DELOITTE & TOUCHE LLP Minneapolis, MN

April 28, 2017

Report of Independent Registered Public Accounting Firms

To the Board of Directors and Members

Aspirity Holdings LLC and Subsidiaries

Minneapolis, Minnesota

We have audited the accompanying consolidated balance sheet of Aspirity Holdings LLC and subsidiaries (the “Company”) as of December 31, 2015, and the related consolidated statements of comprehensive income, changes in members’ deficit, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Aspirity Holdings LLC and subsidiaries as of December 31, 2015, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Baker Tilly Virchow Krause, LLP
Minneapolis, Minnesota

April 15, 2016, except for the effects of the correction of an error discussed in Note 19 as to which the date is May 23, 2016 and the effects of the 2015 discontinued operations discussed in Note 4, as to which the date is April 28, 2017.

Aspirity Holdings, LLC and Subsidiaries

Consolidated Balance Sheets

As of December 31, ~~2015~~2016 and ~~2014~~2015

	2015			2014
	2016			2015
Assets
Current assets
Unrestricted cash	$	21,~~331~~299,~~401~~743		$	21,~~397~~371,~~300~~167
Cash in trading accounts		8,047,331			21,099,652
Restricted cash		219,857			-
Cash collateral		246,000			-
Cash in trading accounts		-			1,800,272
Marketable securities		-			311,586
Cash in collateral accounts		25,025			246,000
Trade accounts receivable, net		5,888,184			2,394,246
Accounts receivable, net of allowance		502,722			3,558,316
Inventory, average cost basis		53,917			-
Prepaid expenses and other current assets		87,106			82,253
Costs and estimated earnings in excess of billings on uncompleted contracts		7,503			-
Assets of discontinued operations - current (see Note 4)		-			11,084,264
Notes receivable, net of deferred gain		795,995			-
Total current assets		2,134,453			18,142,272
Prepaid expenses and other current assets		771,941			416,419
Property, equipment and furniture, net		77,091			217,625
Total current assets		18,142,272			26,619,203
Property, equipment and furniture, net		1,348,311			762,529
Other assets
Intangible assets, net		852,669			269,149
Assets of discontinued operations - non-current (see Note 4)		-			10,325,332
Deferred financing costs, net		314,025			241,744
Total assets	$	2,211,544		$	28,685,229
Restricted cash		1,319,371			1,319,371
Liabilities and Members' Deficit
Real estate held for development		2,714,297			953,462
Investment in convertible notes		502,110			1,604,879
Notes receivable, net of deferred gain		2,586,616			-
Goodwill		1,148,117			-
Deferred tax asset		47,000			-
Other assets		24,466			-
Total assets	$	28,999,254		$	31,770,337
Liabilities and Members’ Equity (Deficit)
Current liabilities
Current portions of debt
Revolver and line of credit	$	1,688,405		$	1,105,259
Revolver and short term debt (see Note 15)	$	-		$	1,212,705
Senior notes		1,214,762			312,068
Renewable unsecured subordinated notes		12,430,151			10,120,175
Renewable unsecured subordinated notes		10,120,175			7,234,559
Accounts payable		1,107,500			2,471,355
Accounts payable - trade		4,376,984			1,544,103
Accrued expenses		741,563			2,090,227
Accrued expenses		2,105,339			681,995
Accrued interest		2,193,408			1,502,761
Accrued compensation		723,355			3,601,282
Liabilities of discontinued operations - current (see Note 4)		-			5,046,443
Accrued interest		1,503,819			849,913
Total current liabilities		16,472,622			22,443,666
Billings in excess of costs and estimated earnings on uncompleted contracts		710,827			-
Obligations under settlement agreement		-			582,565
Total current liabilities		22,443,666			15,911,744
Long-term liabilities
Senior notes		242,232			217,451
Renewable unsecured subordinated notes		17,037,398			14,050,298
Renewable unsecured subordinated notes		14,364,323			10,418,569
Liabilities of discontinued operations - non-current (see Note 4)		-			242,232
Obligations under settlement agreement		-			2,524,448
Total long term liabilities		17,037,398			14,292,530
Total long term liabilities		14,606,555			13,160,468
Total liabilities		33,510,020			36,736,196
Total liabilities		37,050,221			29,072,212
Commitments and contingencies (see Note 16)
Commitments and contingencies
Members' deficit
Members’ equity (deficit)
Series A preferred equity		2,745,000			2,745,000
Common equity		(1,646,963	)		(193,624	)
Term Loan receivable from related party (see Notes 10 and 15)		(15,066,701	)		-
Accumulated other comprehensive income		-			146,749
Common equity		(18,976,775	)		(7,499,580	)
Total members’ equity (deficit)		1,098,037			2,698,125
Total members' deficit		(31,298,476	)		(4,754,580	)
Non-controlling interest		~~(9,807,776~~-	)		-(3,955,159	)
Accumulated other comprehensive income attributed to non-controlling interest		~~658,772~~-			-658,772
Total equity (deficit)		(8,050,967	)		2,698,125
Total deficit		(31,298,476	)		(8,050,967	)
Total liabilities and equity (deficit)	$	28,999,254		$	31,770,337
Total liabilities and members' deficit	$	2,211,544		$	28,685,229

See notes to consolidated financial statements.

5742

Aspirity Holdings, LLC and Subsidiaries

Consolidated Statements of Comprehensive Income

For the Years Ended December 31, ~~2015~~2016 and ~~2014~~2015

	2015			2014
	2016			2015
Revenue
Wholesale trading, net	$	14,293,475		$	38,611,944
Retail energy services		11,678,164			30,109,090
Retail energy services		30,482,812			11,229,476
Financial services (Related party - Note 13)		1,864,199			-
Real estate sales		351,725			-
Total revenue		13,542,363			30,109,090
Management services		710,000			-
Construction services		2,285,998			-
					-
Total sales and services revenue		33,830,535			11,229,476
Total revenue		48,124,010			49,841,420
Costs of sales and services
Cost of retail electricity sold		26,663,003			11,440,672
Cost of retail energy sold		10,009,558			26,663,003
Cost of real estate sold		319,261			-
Gross profit on sales and services		3,532,805			3,446,087
Cost of construction services.		1,703,956			-
Total costs of sales and services .		28,686,220			11,440,672
Gross profit on sales and services		5,144,315			(211,196	)
Operating expenses
Sales and marketing .		1,353,221			324,948
Sales, marketing, and customer service		5,037,755			1,332,721
Compensation and benefits		13,467,931			21,722,319
Other general and administrative		6,831,126			8,672,047
Professional fees		2,463,360			2,487,056
Total operating expenses		11,868,881			10,004,768
Other general and administrative		5,226,002			6,093,843
Operating loss		(8,336,076	)		(6,558,681	)
Trading tools and subscriptions		1,292,662			1,332,804
Total operating expenses .		23,803,176			31,960,970
Operating income (loss)		(4,365,386	)		6,439,778
Other income (expense)
Interest expense		(34,~~568~~327,~~707~~500	)		(2,~~293~~468,~~376~~368	)
Interest income		829,222			142,915
Other income, net		(230,133	)		165,308
Gain on sale of subsidiary		1,343,156			-
Other expense, net		(4,557,633	)		(2,303,060	)
Impairment of convertible notes		(1,250,000	)		-
Net loss from continuing operations		(12,893,709	)		(8,861,741	)
Gain (loss) on foreign currency exchange		356,288			(720,952	)
Discontinued operations (Note 4)
Gain (loss) on sale of marketable securities		(129,743	)		65,655
Net income from discontinued operations		712,364			4,099,698
Other income		1,976,127			145,164
Net loss		(12,181,345	)		(4,762,043	)
Other income (expense), net .		(443,657	)		(2,660,594	)
Net loss from non-controlling interest		(109,638	)		(468,484	)
Income (loss) before income taxes		(4,809,043	)		3,779,184
Net loss attributable to Company		(12,071,707	)		(4,293,559	)
Income tax benefit		(47,000	)		-
Preferred distributions		549,072			549,072
Net income (loss)		(4,762,043	)		3,779,184
Net loss attributable to common	$	(12,620,779	)	$	(4,842,631	)
Net income (loss) attributable to non-controlling interest		(468,484	)		-
Other comprehensive loss:
Net income (loss) attributable to Company		(4,293,559	)		3,779,184
Net loss from non-controlling interest	$	(109,638	)	$	(468,484	)
Preferred distributions		549,072			(549,072	)
Foreign currency translation adjustment		90,840			-
Net income (loss) attributable to common		(4,842,631	)		3,230,112
Attributable to non-controlling interest		(18,798	)		(468,484	)
Other comprehensive income (loss) attributable to non-controlling interest
Net loss attributable to Company		(12,071,707	)		(4,293,559	)
Foreign currency translation adjustment		~~(340,269~~-	)		-(340,269	)
Change in fair value of cash flow hedges.		863,408			-
Change in fair value of cash flow hedges		-			863,408
Unrealized gain (loss) on marketable securities.		(11,116	)		-
Unrealized gain on marketable securities		-			(11,116	)
Comprehensive income (loss) attributable to non-controlling interest		43,539			-
Attributable to the Company		(12,071,707	)		(3,781,536	)
Other comprehensive income (loss) attributable to common
Preferred distributions		549,072			549,072
Foreign currency translation adjustment		-			661,033
Attributable to common	$	(12,620,779	)	$	(4,330,608	)
Change in fair value of cash flow hedges.		-			(1,220,022	)
Unrealized gain (loss) on marketable securities.		-			5,349
Comprehensive income (loss) attributable to common		(4,842,631	)		2,676,472
Comprehensive income (loss) attributable to the Company	$	(4,799,092	)	$	2,676,472

See notes to consolidated financial statements.

5843

Aspirity Holdings, LLC and Subsidiaries

Consolidated Statements of Cash Flows

For the Years Ended December 31, ~~2015~~2016 and ~~2014~~2015

	2015			2014
	2016			2015
Cash flows from operating activities
Net (loss) income	$	(4,762,043	)	$	3,779,184
Net loss	$	(12,181,345	)	$	(4,762,043	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Net income from discontinued operations		712,364			4,099,698
Depreciation and amortization		696,395			869,631
Net loss from continuing operations		(12,893,709	)		(8,861,741	)
Loss (gain) on sale of marketable securities		129,743			(65,655	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Gain on sale of subsidiary		(1,343,156	)		-
Depreciation and amortization		111,722			539,303
Loss on settlement agreement		-			3,607,013
Unit based compensation		655,105			-
Obligations under settlement agreement		(194,188	)		(500,000	)
Gain on sale of marketable securities		-			129,743
Impairment of convertible notes		1,250,000			-
Change in operating assets and liabilities:
Deferred tax asset		(47,000	)		-
Trading accounts		291,104			488,650
(Increase) decrease in:
Collateral deposits		38,475			(246,000	)
Trading accounts		7,909,586			(10,528,239	)
Accounts receivable		(1,341,379	)		(1,680,069	)
Collateral deposits		(246,000	)		-
Prepaid expenses and other current assets		56,953			172,547
Accounts receivable		(1,796,986	)		(1,079,036	)
Accounts payable		439,506			1,745,348
Inventories		(53,917	)		-
Accrued expenses		826,841			1,412,031
Costs and estimated earnings in excess		144,148			-
Accrued compensation		-			(237,092	)
Prepaid expenses and other current assets		(360,188	)		(183,638	)
Accrued interest		751,613			652,848
Increase (decrease) in:
Net cash used for continuing operations		(11,063,770	)		(5,884,432	)
Accounts payable - trade		1,377,268			508,459
Net cash provided by discontinued operations		1,747,833			6,973,613
Accrued expenses		1,414,254			(145,870	)
Net cash (used for) provided by operating activites		(9,315,937	)		1,089,181
Accrued compensation		(3,614,045	)		3,301,843
Accrued interest		651,828			490,155
Billings in excess of costs and estimated earnings		(66,518	)		-
Net cash provided by operating activities		1,089,181			53,847
Cash flows from investing activities
Purchase of property, equipment, and furniture		(477,755	)		(202,759	)
Purchases of property, equipment, and furniture		(20,392	)		(240,479	)
Purchases of marketable securities		~~(5,110,517~~-	)		(15,~~214~~110,~~004~~517	)
Proceeds from sale of marketable securities		~~5,292,360~~-			15,~~229~~292,~~426~~360
Noble Conservation Solutions, Inc. net of cash acquired		68,494			-
Proceeds from Term Loan		3,173,486			-
Discount Energy Group, LLC net of cash acquired		-			(680,017	)
Net cash provided by (used for) continuing operations		3,153,094			(58,636	)
Purchase of convertible notes		-			(1,604,879	)
Net cash used for discontinued operations		(162,852	)		(2,479,736	)
Investment in convertible notes		(147,231	)		-
Net cash provided by (used for) investing activities		2,990,242			(2,538,372	)
Proceeds from sale of real estate held for development		130,965			-
Capital expenditures on real estate held for development		(1,891,800	)		(184,529	)
Repayment of note receivable		345,105			140,964
Advance of note receivable		(747,992	)
Advance of restricted cash		-			(999,183	)
Net cash used in investing activities		(2,538,371	)		(3,514,981	)
Cash flows from financing activities
Deferred financing costs		(~~300~~239,~~792~~401	)		(35300,~~000~~792	)
Proceeds from line of credit		-			700,000
Proceeds from revolver and short term debt		4,345,420			28,977,000
Payments on line of credit		-			(700,000	)
Proceeds from bridge loan		500,000			-
Proceeds (payments) on senior line of credit		862,152			(203,433	)
Payments on revolver and short term debt		(3,496,586	)		(28,869,555	)
Proceeds from revolver		269,543			1,850,000
Issuances of renewable unsecured subordinated notes		9,619,227			10,213,969
Payments on revolver		-			(744,741	)
Redemptions of renewable unsecured subordinated notes		(4,170,700	)		(3,374,420	)
Issuances of renewable unsecured subordinated notes		10,213,969			9,308,708
Contribution from related party on Term Loan		2,008,000
Redemptions of renewable unsecured subordinated notes		(3,374,420	)		(1,640,406	)
Purchase of treasury stock		(25,000	)		-
Preferred distributions		(549,072	)		(549,072	)
Common distributions		~~(5,950,000~~-	)		(41,~~726~~250,~~730~~540	)
Payment of obligations under non-competition agreement		-			(250,000	)
Net cash provided by continuing operations		7,991,888			4,846,590
Net cash provided by financing activities		1,171,380			3,009,326
Net cash used for discontinued operations		(1,103,898	)		(3,675,210	)
Net decrease in cash		(277,810	)		(451,808	)
Net cash provided by financing activities		6,887,990			1,171,380
Effect of exchange rate changes on cash		211,911			(341,387	)
Net increase (decrease) in cash		562,295			(277,811	)
Unrestricted cash
Effect of exchange rate changes on cash		87,104			211,911
Beginning of year		2,397,300			3,190,495
Unrestricted cash and restricted cash
End of year	$	2,331,401		$	2,397,300
Beginning of period		2,331,401			2,397,300
Adjustment for deconsolidation of VIE		(1,461,200	)		-
End of period	$	1,519,600		$	2,331,400

See notes to consolidated financial statements.

5944

Aspirity Holdings, LLC and Subsidiaries

Consolidated Statements of Cash Flows (Continued)

For the Years Ended December, 31 ~~2015~~2016 and ~~2014~~2015

	2015			2014
	2016			2015
Non-cash investing and financing activities:
Non-cash financing activities:
Effective portion of cash flow hedges	$	-		$	(863,408	)
Conversion of bridge loan and accrued interest to common units	$	513,479		$	-
Note receivable from sale of subsidiary, gross	$	12,896,876		$	-
Renewable unsecured subordinated notes Capitalized interest	$	442,308		$	308,982
Less deferred gain on sale		(10,260,568	)		-
Renewals	$	8,771,958		$	7,732,661
Note receivable from sale of subsidiary, net	$	2,636,308		$	-
Acquisition of land for development via foreclosure on mortgage loan	$	-		$	353,504
Acquisition of land for development via assignment and assumption agreement	$	1,083,675		$	304,952
Unrealized gain on marketable securities	$	-		$	11,116
Non-controlling interest	$	(9,339,292	)	$	-
Accumulated other comprehensive income attributed to non-controlling interest		658,772			-
Non-controlling interest due to distribution and reconsolidation of VIE	$	(8,680,520	)	$	-
Supplemental disclosures of cash flow information:
Cash payments for interest	$	2,~~914~~952,~~801~~370		$	12,~~793~~456,~~221~~354
Capitalized interest related to real estate held for development	$	43,958		$	-

See notes to consolidated financial statements.

6045

Aspirity Holdings, LLC and Subsidiaries

Consolidated Statements of Changes in Members’ ~~Equity~~Deficit

For the Years ended December 31, ~~2015~~2016 and ~~2014~~2015

	Series A Preferred Equity		Common Equity			~~Accumulated~~Term ~~Other~~Loan ~~Comprehensive~~receivable ~~Income~~from related party			~~Total~~Accumulated ~~Members’~~Other ~~Equity~~Comprehensive Income			~~Non-Controlling~~Total ~~Interest~~Members' Equity			~~Accumulated Other Comprehensive Income Attributed to~~ Non- Controlling Interest			~~Total~~Accumulated ~~Equity~~Other Comprehensive Income Attributed to Non- Controlling Interest			Total Equity
Balance - December 31, 2013	$	2,745,000	$	1,302,994		$	700,389		$	4,748,383		$	-		$	-		$	4,748,383
Balance - December 31, 2014	$	2,745,000	$	(193,624	)	$	-		$	146,749		$	2,698,125		$	-		$	-		$	2,698,125
Net income		-		3,779,184			-			3,779,184			-			-			3,779,184
Net loss		-		(4,293,559	)		-			-			(4,293,559	)		(468,484	)		-			(4,762,043	)
Other comprehensive income		-		-			~~(553,640~~-	)		~~(553~~512,~~640~~023	)		-512,023			-			~~(553,640~~-	)		512,023
Preferred distributions		-		(549,072	)		-			~~(549,072~~-	)		-(549,072	)		-			~~(549,072~~-	)		(549,072	)
Common distributions		-		(45,~~726~~950,~~730~~000	)		-			~~(4,726,730~~-	)		-(5,950,000	)		-			~~(4,726,730~~-	)		(5,950,000	)
Balance - December 31, 2014	$	2,745,000	$	(193,624	)	$	146,749		$	2,698,125		$	-		$	-		$	2,698,125
Non-controlling interest due to distribution and reconsolidation of VIE		-		3,486,675			-			(658,772	)		2,827,903			(3,486,675	)		658,772			-
Net income (loss)		-		(4,293,559	)		-			(4,293,559	)		(468,484	)		-			(4,762,043	)
Balance - December 31, 2015	$	2,745,000	$	(7,499,580	)	$	-		$	-		$	(4,754,580	)	$	(3,955,159	)	$	658,772		$	(8,050,967	)
Other comprehensive income		-		-			512,023			512,023			-			-			512,023
Net loss		-		(12,071,707	)		-			-			(12,071,707	)		(109,638	)		-			(12,181,345	)
Preferred distributions		-		(549,072	)		-			(549,072	)		-			-			(549,072	)
																						-
Common distributions		-		(5,950,000	)		-			(5,950,000	)		-			-			(5,950,000	)
Other comprehensive income		-		-			-			-			-			-			90,840			90,840
Non-controlling interest due to distribution and reconsolidation of VIE		-		9,339,292			(658,772	)		8,680,520			(9,339,292	)		658,772			-
																						-
Balance - December 31, 2015	$	2,745,000	$	(1,646,963	)	$	-		$	1,098,037		$	(9,807,776	)	$	658,772		$	(8,050,967	)
Preferred distributions		-		(549,072	)		-			-			(549,072	)		-			-			(549,072	)
Unit based compensation		-		655,105			-			-			655,105			-			-			655,105
Amendment of Term Loan		-		-			(17,074,701	)		-			(17,074,701	)		-			-			(17,074,701	)
Contribution from related party		-		-			2,008,000			-			2,008,000			-			-			2,008,000
Conversion of bridge loan and accrued interest to issuance of common units		-		513,479			-			-			513,479			-			-			513,479
Treasury stock		-		(25,000	)		-			-			(25,000	)		-			-			(25,000	)
Adjustment due to deconsolidation of VIE		-		-			-			-			-			4,064,797			(749,612	)		3,315,185
Balance - December 31, 2016	$	2,745,000	$	(18,976,775	)	$	(15,066,701	)	$	-		$	(31,298,476	)	$	-		$	-		$	(31,298,476	)

See notes to consolidated financial statements.

6146

Aspirity Holdings, LLC and Subsidiaries

Notes to Consolidated Financial Statements

1.	Organization and Description of Business

Organization & Restructuring

Aspirity Holdings, LLC (“Aspirity” or the “Company”), known as Twin Cities Power Holdings, LLC or “TCPH” prior to July 14, 2015, is a Minnesota limited liability company formed on December 30, 2009~~, but had no assets or operations before December 31, 2011~~. On November 14, 2011, TCPH entered into an Agreement and Plan of Reorganization (the “Reorganization”) with its then current members and Twin Cities Power, LLC (“TCP”), Cygnus Partners, LLC (“CP”), and Twin Cities Energy, LLC (“TCE”) which were affiliated through common ownership. Effective December 31, 2011, following receipt of approval from the Federal Energy Regulatory Commission (“FERC”), the members of TCP, CP, and TCE each contributed all of their ownership interests in these entities to TCPH in exchange for ownership interests in TCPH. Consequently, after the Reorganization, which made TCPH a holding company and the sole member of each of TCP, CP, and TCE, the financial statements are presented on a consolidated basis. The Reorganization was accounted for as a transaction among entities under common control. TCE and its wholly-owned subsidiary, Twin Cities Power – Canada, Ltd. (“TCPC”), became inactive in the third quarter of 2012.

In ~~2013 and 2014~~2015, the Company ~~formed~~restructured ~~additional~~according first- and second-tier subsidiaries. First-tier subsidiaries included Retail Energy Holdings, LLC (“REH”), formed on October 25, 2013 in anticipation of the acquisition of Discount Energy Group, LLC or “DEG”, Cyclone Partners LLC (“Cyclone”), formed on October 23, 2013 to ~~take~~a ~~advantage~~plan ofincorporating ~~certain investment opportunities present in~~ the ~~residential~~following ~~real~~key estate market, and Apollo Energy Services, LLC (“Apollo”), formed on October 27, 2014 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.features:

~~With respect~~● toForm ~~second-~~three new first tier subsidiaries, as- oftwo ~~March~~to ~~31,~~house ~~2015~~new retail energy (Aspirity Energy) and financial services (Aspirity Financial) operations and one for the Company’s legacy businesses, ~~TCP~~Krieger ~~had~~Enterprises; ● Sell one of three ~~active~~wholesale ~~subsidiaries~~trading -businesses, Twin Cities Power and Summit Energy, ~~LLC~~its ~~(“SUM”)~~wholly-owned subsidiary, ~~Chesapeake~~ ~~Trading~~to ~~Group,~~Angell ~~LLC~~Energy; ● Transfer the Legacy Businesses constituting the remaining wholesale trading operations (~~“CTG”),~~Chesapeake Trading Group and ~~Minotaur~~Cygnus Energy Futures), ~~LLC~~Retail Energy Holdings (“~~MEF~~REH”), ~~deactivated~~and inthe diversified investments portfolio from the ~~second quarter~~Company ofto ~~2015)~~Enterprises; ~~Cygnus~~● ~~had~~Create ~~one~~a -Term ~~Cygnus~~Loan ~~Energy~~between ~~Futures,~~Aspirity ~~LLC~~Financial ~~(“CEF”);~~and Enterprises to assure Note holders that part of the cash flows generated by the legacy businesses are used to pay interest and ~~REH~~principal ~~had~~on ~~three~~the -Notes ~~Town~~originally ~~Square~~issued ~~Energy,~~to ~~LLC (“TSE”),~~finance ~~Town~~them; ~~Square~~● ~~Energy~~Change ~~East,~~the ~~LLC~~name ~~(“TSEE”,~~of ~~formerly~~the ~~DEG),~~Company from Twin Cities Power Holdings to Aspirity Holdings to reflect the Company’s new direction and ~~Town~~focus; ~~Square~~● ~~Energy~~Exit ~~Canada,~~the ~~Ltd.~~legacy ~~(“TSEC”). Effective~~businesses ~~April~~via ~~30,~~the ~~2015,~~spin-off ~~TCP~~100% ~~distributed~~of the ~~ownership~~common equity interests of ~~CTG~~Enterprises to ~~TCPH~~Aspirity’s then members Timothy S. Krieger (99.50%) and itSummer ~~became~~Enterprises LLC (0.50%), a ~~first~~company ~~tier~~controlled ~~subsidiary~~by ofhim for the ~~Company~~ benefit of his children; and ● Issue new common equity interests to Aspirity’s management.

~~Operations~~Effective ~~Prior~~with the Spinoff on November 1, 2015, we exited all wholesale trading and diversified investment activity and have no plans to engage in such in the ~~Restructuring~~future, ~~and~~therefore these operations are reported as discontinued operations. Although, due to the Distribution we no longer own REH, its retail energy services operations remain in continuing operations through March 30, 2016 due to not being considered a strategic shift from future operations. After the Distribution but prior to March 30, 2016, the financial results of Enterprises were consolidated with those of the Company as a variable interest entity or VIE. Historically, these segments constituted significant parts of our business, and consequently, our future financial statements will be significantly different from those of the past.

~~Prior~~Consistent towith the ~~Restructuring~~change ~~and~~in ~~Distribution~~strategy, the Company ~~had~~now ~~three~~has start-up operations in two business segments ~~used~~- tofinancial ~~measure~~services ~~its~~and retail ~~activity~~energy. –Our ~~wholesale trading,~~intention is to expand our retail energy ~~services,~~operations as we receive the necessary licenses and ~~diversified~~establish ~~investments.~~the necessary ~~Specifically,~~relationships ~~it:~~with utilities and expect that we will begin to structure financial services offerings in 2017.

●See also ~~Traded financial contracts in wholesale electricity markets managed by Independent System Operators or Regional Transmission Organizations (collectively,~~ “~~ISOs”),~~Note ~~including~~3 ~~those~~– ~~managed~~Variable byInterest ~~the Midcontinent Independent System Operator (“MISO~~Entities”), ~~the PJM Interconnection (~~“~~PJM”),~~Note ~~ISO~~5 ~~New England (“ISO~~-~~NE”),~~ ~~the~~Summary ~~New~~Consolidating ~~York~~Financial ~~Independent System Operator (“NYISO~~Information”), and ~~the Electric Reliability Council of Texas (~~“~~ERCOT”);~~Note ●4 ~~Traded electricity and other energy~~-~~related~~ ~~derivative~~Discontinued ~~contracts on exchanges regulated the Commodity Futures Trading Commission (“CFTC~~Operations”~~) and operated by the Intercontinental Exchange® (“ICE”), the Natural Gas Exchange Inc~~. ~~(“NGX”), and the CME Group (“CME”);~~

6247

●	Provided electricity supply services to retail customers in 8 states that permit retail choice (Connecticut, Maryland, Massachusetts, New Hampshire, New Jersey, Ohio, Pennsylvania, and Rhode Island); and
●	Was engaged in certain asset management activities, including real estate development and investments in privately held businesses.

Liquidity, Financial Condition & Management’s Plans

~~Effective~~The ~~June~~Company 1has financed its operations to date principally through collections of energy revenues, ~~2015~~Note sales, and Term Loan receipts. For the ~~Company~~year ~~entered~~ended ~~into~~December 31, 2016, on a consolidated basis, the Company reported a net loss of $12~~-month~~,893,000 ~~agreement~~and ~~with~~cash ~~Ultra~~used ~~Green~~for continuing tooperations ~~provide~~of ~~CEO~~$11,064,000. ~~services~~As (of December 31, 2016, the ~~“UG~~Company ~~Services~~had ~~Contract”)~~unrestricted cash, negative working capital, and total members’ deficit of $1,300,000, $14,388,000, and $31,298,000, respectively. There is a further possibility these negative financial metrics will not turn positive for at least the next 12 months.

The ~~Restructuring~~Company currently relies on Notes and Term Loan receipts as its principal source of funding until it can generate sufficient operating cash flow to fund its ongoing business. As of December 31, 2016, $12,430,000 of Notes will mature prior to December 31, 2017, which is approximately the amount of Notes maturing within 12 months of the issuance date. Historically, a significant portion of maturing Notes renew, which does not require a cash outlay by the Company. However, the decision to redeem or renew is solely at the discretion of the noteholder and not the Company.

~~Since~~While ~~mid-2014,~~ the ~~Board~~Company ofexpects ~~Directors~~that ~~has~~Notes ~~been~~will ~~considering~~be ~~ways~~redeemed at rates similar to ~~better~~those ~~position~~that have occurred historically, management’s analysis of the ability of the Company to ~~access~~continue ~~capital~~as ~~markets,~~a ingoing ~~particular~~ concern must consider the possibility that ~~for~~all ~~public~~Notes ~~equity.~~maturing ~~Ultimately,~~for at least the ~~Board~~next ~~concluded~~12 ~~that~~months from the ~~Company’s~~issuance ~~regulatory~~of ~~exposure~~the ~~and~~financial ~~earnings~~statements ~~volatility, particularly~~will ~~that~~be ~~related~~redeemed. If such events were to occur, the Company ~~wholesale~~would ~~trading~~not ~~businesses,~~have ~~needed~~enough liquidity to bemeet ~~substantially~~all ~~reduced~~redemption orrequests, ~~eliminated~~given inthe ~~order~~Company ~~for~~currently ~~such~~has no other sources of capital ~~efforts~~that tocould be ~~successful~~accessed onto ~~the~~cover ~~desired~~increased ~~scale~~redemptions from these Notes.

OnTo ~~May~~evaluate 27the Company’s ability to continue as a going concern, ~~2015~~the Company considered both the aggregation of the negative financial metrics, as noted above, and the ~~Board~~possibility ~~approved~~these awill ~~plan~~not toturn ~~restructure~~positive for at least the ~~business~~next ~~via~~12 months. Further, the ~~sale~~Company assessed the possibility of ~~TCP,~~the ~~spinning~~redemption ~~out~~of all Notes maturing in the ~~remaining~~next ~~legacy~~12 ~~businesses~~months by the respective noteholders. asThese ~~defined~~uncertainties ~~below,~~suggest ~~and~~there ~~recasting~~is substantial doubt as to the Company’s ~~solely~~ability to continue as a ~~retail~~going ~~energy~~concern ~~and~~within one ~~financial~~year ~~services~~from ~~business (~~the ~~“Restructuring”). Overall,~~date ~~the~~that ~~Restructuring~~these ~~incorporated~~financial ~~several~~statements ~~major~~were ~~steps~~issued.

~~New~~Management ~~first-~~has ~~and~~plans ~~second-tier~~intended ~~subsidiaries were created~~ to ~~facilitate~~mitigate the ~~process.~~conditions ~~The~~described ~~new first-tier subsidiaries consisted of Krieger Enterprises, LLC (“Enterprises”), Aspirity Energy LLC (“Aspirity Energy”), and Aspirity Financial LLC (“Aspirity Financial”)~~above. ~~Enterprises~~These ~~was~~plans ~~formed~~include togrowing ~~accept~~customer ~~the~~acquisitions ~~contribution~~such ofthat ~~the Legacy Businesses as defined below.~~positive ~~The~~operating ~~new~~cash ~~second-tier~~flow ~~entities,~~is ~~subsidiaries~~generated ofon ~~Aspirity~~a ~~Energy,~~sustained ~~were~~basis ~~formed~~beginning ~~to conduct business~~ in the ~~various~~first ~~areas~~half of ~~the~~2018, ~~U.S. that~~continuing ~~benefit~~collection ~~from~~on ~~active~~the ~~wholesale~~Term Loan, and ~~restructured~~continuing ~~retail~~to ~~electricity~~sell ~~markets~~Notes. ~~- Aspirity Energy Northeast LLC (“AENE”)~~Further, ~~Aspirity~~ ~~Energy~~although ~~Mid-States~~the ~~LLC~~Company ~~(“AEMS”),~~intends ~~and~~to ~~Aspirity~~evaluate ~~Energy~~other ~~South~~sources ~~LLC~~of ~~(“AES”).~~debt ~~Aspirity~~and ~~Financial~~equity ~~was~~financing, there ~~formed~~can tobe ~~provide~~no ~~energy-related~~assurance ~~financial~~that ~~services~~these toefforts ~~companies~~will ~~and~~be ~~households~~successful.

OnWhile ~~June 1, 2015, pursuant to an Equity Interest Purchase Agreement (~~the ~~“Purchase Agreement”), the~~ Company ~~sold~~believes ~~100% of~~that ~~the~~payments ~~outstanding~~from ~~equity~~Enterprises ~~interests~~on ofthe ~~TCP~~Term ~~and SUM to Angell Energy~~Loan, ~~LLC,~~anticipated ~~a Texas limited liability company (“Angell”), for a purchase price of $20,741,729, paid with $500,000~~ cash ~~and~~generated afrom ~~secured~~operating ~~promissory note of $20~~activities,~~240,729~~ ~~bearing interest at~~availability ~~an annual rate~~ of ~~6.00%~~trade ~~and payable in 12 quarterly installments of $1~~credit,~~855,670~~ ~~each~~and ~~with~~anticipated aproceeds ~~final~~from ~~maturity~~the ofNotes ~~June~~Offering 1,will ~~2018~~be ~~(the “Original~~sufficient ~~Angell~~to ~~Note”).~~meet ~~Also~~operating atcash ~~such~~requirements ~~closing, the Company~~ and ~~Angell~~Note redemption ~~entered~~obligations ~~into a sublease~~ for the ~~Lakeville~~next ~~office of~~twelve ~~TCP and Apollo and Angell entered into two agreements - a 6-month contract to provide certain management~~months, ~~operations,~~the ~~and~~Company ~~administrative services~~is ~~and~~unable ~~a 24-month software license, subject~~ to ~~renewal~~conclude ~~for~~that ~~successive~~it ~~one~~is ~~year~~probable ~~periods~~that ~~(the “Angell Services Contracts”).~~management’s ~~The~~plans ~~Company~~will ~~also~~fully ~~assumed~~mitigate the ~~FERC~~conditions ~~settlement of $2,912,825~~identified.

After closing, Angell decided that it no longer desired to sublease the Lakeville office of TCP nor employ the associated personnel. Angell offered the Company the opportunity to cancel the sublease and to re-employ such personnel in exchange for a reduction of the purchase price. Consequently, effective September 2, 2015, an amendment to the Purchase Agreement was executed, reducing the purchase price to $15,000,000. The Original Angell Note was also amended and restated and the principal balance was reduced to $15,024,573, the interest rate remained the same, the quarterly payment was reduced to $1,063,215, and the final maturity date was extended to June 1, 2019 (the “Amended Angell Note”). On November 5, 2015, the services agreement was terminated and on November 5, 2015, Angel purchased a perpetual software license to replace the 24 month agreement.

Effective July 1, 2015, the Company completed an internal reorganization that effected the separation of the Company’s wholesale energy trading, real estate investments, investments in private companies, legacy retail energy business, and certain other assets and obligations (collectively, the “Legacy Businesses”) from its new Aspirity subsidiaries. Specifically, the internal reorganization incorporated the following actions:

● Enterprises received the following from the Company:

● 100% of the outstanding equity interests of all active subsidiaries, including Apollo, CTG, Cygnus, REH, and Cyclone; ● 100% of the outstanding equity interests of all inactive subsidiaries, including: Athena Energy Futures LLC; Minotaur Energy Futures LLC; Twin Cities Energy LLC and its subsidiary Twin Cities Power-Canada, Ltd.; TC Energy Trading, LLC; Twin Cities Power Services, LLC; and Vision Consulting, LLC; ● Certain other assets owned directly by the Company, including the Amended Angell Note, the Series C Notes of Ultra Green, investments in certain real estate projects, and the restricted cash pledged to a Canadian court in connection with the ex-employee litigation; and ● The UG and Angell Services Contracts.

●

Enterprises assumed certain current liabilities and obligations owed directly by the Company such as leases for office space and equipment; and

●

Enterprises borrowed an aggregate principal amount of $22,206,113 with a weighted average interest rate of 14.08% and a maturity date of December 30, 2019 from Aspirity Financial (the “Term Loan”). Although initially an intercompany relationship and eliminated in consolidation, the loan agreement between the parties is constructed on an arm’s length basis, contains customary protective provisions for the lender, including certain guarantees, collateral, and covenants, and ensures that the cash flows generated by the Legacy Businesses continue to be used to pay the interest and principal on the Renewable Unsecured Subordinated Notes (the “Notes”) outstanding as of June 30, 2015 (the “Term Loan Notes”).

Effective November 1, 2015, the last major step in the Restructuring occurred - the spin-off or “Distribution” of 100% of the equity interests of Enterprises to the Company’s common equity owners, thus completing the legal separation of the Legacy Businesses from the Aspirity companies. Concurrently with the Distribution, executive management changed and new common equity owners were added pending FERC approval of the change in control. Such approval was obtained as of March 18, 2016.

After the Restructuring and Distribution

After the Distribution, the Company has start-up operations in two business segments - financial services and retail energy.

Further, while the Company no longer has an ownership interest in Enterprises and its subsidiaries after the Distribution Date, an assessment of the relationship between the entities as of December 31, 2015 with respect to ASC 810 Consolidation (“ASC 810”) guidance was performed. Pursuant to such assessment, it was concluded that Aspirity should consolidate Enterprises as a VIE as of December 31, 2015. ASC 810 also requires the Company to reevaluate the status of Enterprises as a VIE on a regular basis.

Note that while the Company includes the assets, liabilities, equity, and results of operations of Enterprises in its consolidated financial statements, the Company does not have rights to those assets or responsibility for such claims on assets other than pursuant to its rights under the Term Loan.

Finally, in the future, the Company’s reports of its financial condition and results of operations will be significantly different from those of the past. For example, on a consolidated basis, wholesale trading activities accounted for 29.7% and 77.5% of total revenues of $48,124,000 and $49,841,420 for the years ended December 31, 2015 and 2014, respectively. The Company exited this business effective with the Distribution and has no plans to engage in such activities in the future. With respect to retail energy, while Aspirity Energy has commenced operations, it has yet to record significant results and the Company’s historical financial statements reflect the results of operations of REH and its subsidiaries which it no longer owns or operates. Finally, the Company no longer intends to pursue any diversified investment activity.

Liquidity and Financial Condition

The Company and Enterprises on a consolidated basis reported a net loss of $4,762,000 for the year ended December 31, 2015 and had unrestricted cash, other liquid assets (deposits in trading accounts, cash collateral, and trade receivables), negative working capital and deficit equity of $2,331,000, $14,182,000, $4,301,000, and $8,051,000, respectively, as of the same date. See “Note 3 – Summary Consolidating Financial Data”.

Aspirity Energy and Aspirity Financial are start-up companies in the retail energy and financial services industries, respectively, and are not expected to have significant revenue-generating operations until the middle of 2016 at the earliest. Prior to that, the Company will rely on the timely payment of the Term Loan to repay Term Loan Notes as they are redeemed and on its ability to sell Notes in order to fund start-up operations. Enterprises’ ability to make timely payments on the Term Loan depends in part on the operations of its Legacy Businesses which were not profitable in 2015. In the event amounts owed to us are paid late or not paid, our ability to fund operations, sell new Notes, and repay existing Notes will be negatively impacted. See “Note 20 - Debt” and “Note 27 - Subsequent Events”.

While the Company believes that payments from Enterprises on the Term Loan, anticipated cash generated from operating activities, availability of trade credit with respect to power purchases, and anticipated proceeds from our Notes Offering will be sufficient to meet operating cash requirements and obligations under the Notes and Term Loan Notes through at least December 31, 2016, there can be no assurance that this will prove to be the case. Consequently, the Company regularly evaluates other sources of debt financing and is also considering seeking additional equity capital to meet its funding needs. However, there can be no assurance that these efforts will prove to be successful.

2.	Summary of Significant Accounting Policies

Principles of Consolidation

The Company evaluates the need to consolidate affiliates based on standards set forth in ASC 810 Consolidation (“ASC 810”).

In determining whether we have a controlling interest in an affiliate and the requirement to consolidate the accounts of an entity, management considers factors such as our ownership interest, our authority to make decisions, contractual and substantive participating rights of owners, as well as whether the entity is a variable interest entity or “VIE”.

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties or whose equity investors lack any of the characteristics of a controlling financial interest. A variable interest is an investment or other interest that will absorb portions of a VIE’s expected losses or receive portions of the entity’s expected residual returns. Variable interests are contractual, ownership, or other pecuniary interests that change with changes in the fair value of the entity’s net assets. A party is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides the party with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances.

The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries as well as Enterprises and its subsidiaries. All significant consolidated transactions and balances have been eliminated in consolidation.

Variable Interest Entities

The Company follows ASC 810-10-15 guidance with respect to accounting for variable interest entities (each, a “VIE”). These entities do not have sufficient equity at risk to finance their activities without additional subordinated financial support from other parties or whose equity investors lack any of the characteristics of a controlling financial interest. A variable interest is an investment or other interest that will absorb portions of a VIE’s expected losses or receive portions of its expected residual returns and are contractual, ownership, or pecuniary in nature and that change with changes in the fair value of the entity’s net assets. A reporting entity is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides it with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of the power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances.

~~Krieger~~As of ~~Enterprises~~December 31, 2016 and 2015, the Company consolidated zero and one VIE, respectively.

At December 31, 2015, an assessment of the relationship between the Company and Enterprises was performed as a result of the Restructuring. Due to related party considerations, delay in the transfer of governance rights, and the nature and size of the Term Loan between the two parties that could result in losses, the Company may hold a controlling financial interest in Enterprises, and consequently should consolidate it as a VIE as of December 31, 2015. The relationship is subject to ongoing reconsideration based on changes in facts and circumstances.

Ultra Green Packaging

At December 31, 2015, an assessment of the relationship between Enterprises and Ultra Green Packaging, Inc. ("UG") was performed as a result of the investment in UG's Series C Convertible Promissory Notes (the "Series C Notes"), entry into a services contract, and the purchase of certain mortgage notes receivable.

During 2014, Enterprises invested $1,500,000 in the Series C Notes and also entered into an agreement to provide executive services to UG. The term of the contract is for twelve months and either party can terminate the agreement upon thirty days' written notice. During 2015, Enterprises loaned UG $325,000 in the form of four notes, all secured by a first mortgage on a production facility in Devil's Lake, North Dakota and bearing interest at 10% per annum. The notes are due upon the closing of the sale of the property and interest payments are due beginning September 1, 2015. In connection with the issuance of the notes, Ultra Green issued the Company four warrants expiring at various dates in 2025 to purchase 325,000,000 shares of its common stock at an exercise price of $0,001 per share. Enterprises may continue to provide financial support to UG in the future under similar terms. Also during 2015, an impairment of $1,250,000 was recognized on the Series C Notes, resulting in a fair value of $502,110 on the balance sheet as of year-end.

Even though Enterprises holds what might be considered to be a variable interest (the Series C Notes and mortgage notes) in UG, it is not the primary beneficiary as it fails both the power and losses/benefits criteria for primary beneficiary determination. Thus as of December 31, 2015, Enterprises did not consolidate UG.

See also Note 6 - Fair Value Measurements, Note 13 - Notes Receivable, and Note 14 - Investment in Convertible Notes.

Angell

At December 31, 2015, an assessment of the relationship between the Company and Angell was performed as a result of the sale of TCP on June 1, 2015. See “Note 1 – Organization and Description of Business – The Restructuring”. The Company estimates that total assets of Angell immediately after closing were substantially equal to the purchase price. Angell is a VIE since the equity at risk is small compared to the sale price. Further, the Company held a variable interest in the form of the Angell note as adjusted and paid down in the amount of $12,896,875. The receivable amount carried on the Company’s books net of the deferred gain of $10,260,572 is $2,636,303. The Angell note represents the Company’s maximum loss in the VIE. However, the Company has no power to direct any of the activities of Angell, therefore it does not have a controlling financial interest, thus it is not considered a primary beneficiary, and consequently, as of December 31, 2015, the Company did not consolidate Angell. The Company does not provide, nor does it intend to provide, any other financial support to Angell.

Use of Estimates

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

~~Cash Equivalents~~49

Cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. As of December 31, 2015 and 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

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

Retail Energy Services

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

~~During~~Prior to Amendment 3, interest income on the ~~year~~Term ~~ended~~Loan ~~December~~was ~~31,~~recognized ~~2014~~as financial services revenue in the period that the interest was earned. After Amendment 3, the Company ~~changed~~accounted ~~its~~for ~~estimate~~the ~~with~~Term ~~respect~~Loan toas ~~retail~~a ~~sales~~receivable offrom ~~electricity~~a ~~and~~related ~~recorded~~party, ana contra-equity account, ~~adjustment~~and ofwill ~~$465~~use the cost recovery method to account for payments received. Therefore,~~000~~ subsequent to ~~unbilled~~November 1, 2016, the Company will no longer recognize revenue associated with the Term Loan.

~~Diversified~~Term ~~Investments~~Loan Receivable From Related Party

~~Revenues~~Prior ~~from~~to ~~real~~Amendment ~~estate developments~~3, ifthe ~~any~~Company accounted for the Term Loan receivable as an asset. After Amendment 3, ~~are~~the ~~recognized~~Company ataccounted for the Term ~~time~~Loan ofas a ~~sale~~receivable ~~closing~~from ifa ~~all~~related ~~significant~~party, ~~conditions~~a ~~are~~contra-equity ~~satisfied~~account, ~~including~~ ~~adequate~~and ~~down~~will ~~payment,~~use ~~reasonable~~the ~~assurance~~cost ofrecovery ~~collectability~~method ofto ~~any~~account ~~notes~~for payments received. Under this method, ~~and~~cash ~~completion~~receipts ofare ~~other~~first ~~contractual requirements.~~applied ~~Recognition~~to ofreduce ~~all~~the orprincipal ~~part~~balance of the ~~revenue~~receivable and issecond ~~deferred~~to ifincome ~~any~~after ~~significant~~all ~~conditions~~principal ~~are~~has ~~not~~been ~~satisfied~~repaid. See “Note 10 – Term Loan”.

Revenues from administrative services and software licenses are recognized on a monthly basis in accordance with the respective agreements with third parties.

Revenue from construction services is accounted for using the percentage of completion method. Completion percentages are calculated by dividing actual costs incurred to date by the total estimated costs to complete the agreement. Costs-to-complete include all direct material and labor costs, indirect costs related to contract performance such as indirect labor, supplies, tools, and repairs, and estimated earnings. Long term contracts are any that span a period-end. This method is used because management considers total costs to be the best available measure of progress on these contracts.

Changes in job performance, job conditions, estimated profit or loss, and final contract settlements may result in revisions to costs and income. Revisions are recognized in the period in which determined and such adjustments could be significant. The asset “costs and estimated earnings in excess of billings on uncompleted contracts” represents revenues recognized in excess of amounts billed. The liability “billings in excess of costs and estimated earnings on uncompleted contracts” represents billings in excess of revenues recognized.

The financial statements include amounts based on management’s best estimates and judgments, the most significant of which relate to costs-to-complete. These estimates may be adjusted as more current information becomes available, and any adjustment could be significant.

Derivative Instruments

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

Our retail operations follow the guidance of ASC 815 Derivatives and Hedging (“ASC 815”) that permits “hedge accounting” under which the effective portion of gains or losses from the derivative and the hedged item are recognized in earnings in the same period.

To qualify for hedge accounting, the hedge relationships must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis.

“Hedge effectiveness” is the extent to which changes in the fair value of the hedging instrument offset the changes in the cash flows of the hedged item. Conversely, “hedge ineffectiveness” is the measure of the extent to which the change in fair value of the hedging instrument does not offset those of the hedged item. If a transaction qualifies as a “highly effective” hedge, ASC 815 permits matching of the timing of gains and losses of the hedged item and the hedging instrument.

For a cash flow hedge, the effective portion of any change in the hedging instrument’s fair value is recorded in accumulated other comprehensive income or “AOCI” until the change in value of the hedged item is recognized in earnings.

Financial Instruments

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

67Financial instruments that subject the Company to concentrations of credit risk consist principally of accounts receivable, deposits in collateral accounts, and the Term Loan.

~~Foreign~~Financial ~~Currencies~~instruments that may expose the Company to fair value risk from time to time include asset categories such as cash equivalents and marketable securities and liabilities such as borrowings under various credit agreements.

AFair ~~portion~~Value 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.Measurements

~~For~~The ~~foreign~~Fair ~~subsidiaries~~Value ~~whose~~Measurement ~~functional~~Topic ~~currency is the local foreign currency, balance sheet accounts are translated at exchange rates in effect at the end~~ of ~~the~~FASB’s ~~month~~ASC ~~and~~establishes ~~income~~a ~~statement~~fair ~~accounts~~value ~~are~~hierarchy ~~translated~~that atprioritizes ~~average monthly exchange rates for~~ the ~~period.~~ ~~Foreign~~inputs ~~currency transactions denominated in a foreign currency result in gains and losses due~~ to ~~the~~valuation ~~increase or decrease~~techniques inused ~~exchange~~to ~~rates~~measure ~~between~~fair ~~periods~~value. ~~Translation~~The ~~gains~~three ~~and~~types ~~losses are included as a separate component~~ of ~~equity.~~valuation ~~Gains~~inputs ~~and~~in ~~losses from~~the ~~foreign~~fair ~~currency~~market ~~transactions~~hierarchy are ~~included~~as ~~in other income or expense.~~follows:

~~Foreign currency~~● ~~transactions~~“Level ~~resulted~~1 inputs” are quoted prices in aactive ~~gain~~markets offor ~~$356,288~~identical ~~and~~assets aor ~~loss~~liabilities. of● ~~$720,952~~“Level 2 inputs” are inputs other than quoted prices that are observable either directly or indirectly for the ~~years~~asset ~~ended~~or ~~December~~liability. ~~31,~~● ~~2015~~“Level ~~and~~3 ~~2014,~~inputs” ~~respectively~~are unobservable inputs for which little or no market data exists.

~~Concentrations~~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 ~~Credit~~the ~~Risk~~underlying securities are also classified as Level 1.

~~Financial~~The ~~instruments~~fair ~~that~~values ~~subject~~of ~~the~~financial ~~Company~~instruments tothat ~~concentrations~~are ofnot ~~credit~~publicly ~~risk~~traded ~~consist~~in ~~principally~~liquid ofmarkets, ~~deposits~~but indo ~~trading~~have ~~accounts~~characteristics ~~and accounts~~similar ~~receivable.~~to ~~The~~observable market ~~Company~~information ~~has~~such aas ~~risk~~wholesale ~~policy~~commodity ~~that~~prices, ~~includes~~interest ~~value-at-risk calculations~~rates, ~~position~~credit ~~limits~~margins, ~~stop loss limits~~maturities, ~~stress~~ ~~testing~~collateral, ~~system~~and ~~controls,~~the ~~position~~like ~~monitoring,~~upon which ~~liquidity~~valuations ~~guidelines,~~are ~~and~~based ~~compliance~~are ~~training~~categorized in Level 2.

AtFinancial ~~any~~instruments ~~given~~that ~~time,~~are ~~there~~not ~~may~~traded bein ~~concentrations~~publicly ofquoted ~~receivables~~markets ~~balances~~or ~~with~~that ~~one~~are oracquired ~~more~~based ofon prices and terms determined by direct negotiation with the ~~exchanges~~issuer ~~upon~~are ~~which~~classified weas ~~transact~~Level ~~our wholesale~~3. ~~business~~Level ~~or,~~3 insecurities ~~the~~are ~~case~~carried ofat ~~retail~~book value which management believes approximates fair value, ~~one~~until orcircumstances ~~more~~otherwise ofdictate ~~the~~while ~~utilities~~Level ~~operating~~3 inderivatives ~~purchase~~are ofadjusted ~~receivables~~to ~~states~~fair invalue ~~which we~~based doon ~~business~~appropriate mark-to-model methodologies.

~~Fair Value~~50

~~The~~Generally, ~~fair~~with ~~values~~respect to valuation of ~~the~~Level ~~Company’s~~3 ~~cash~~instruments, ~~accounts~~significant ~~receivable,~~changes ~~note~~in ~~receivables,~~inputs ~~revolver,~~will ~~and~~result ~~accounts~~in ~~payable~~higher ~~were~~or ~~considered~~lower fair value measurements, toany ~~approximate~~particular ~~their~~calculation ~~carrying~~or ~~values~~valuation atmethodology ~~December~~may ~~31,~~produce ~~2015~~estimates ~~and~~that ~~2014~~may ~~due~~not tobe ~~the~~indicative ~~short-term~~of ~~nature~~net realizable value or reflective of ~~the~~future ~~accounts~~fair values, and such variations could be material.

~~Management~~From ~~believes~~time ~~the~~to ~~carrying~~time, ~~values of~~ the Company’s ~~notes~~may ~~payable~~engage ~~and~~or ~~Notes~~consult ~~reasonably~~with ~~approximate~~third ~~their~~parties ~~fair~~such ~~value~~as atappraisers, ~~December 31~~brokers, ~~2015~~or ~~and~~investment ~~2014~~bankers ~~due~~ to ~~the~~assist management ~~relatively~~in ~~new~~its ~~age~~valuation of ~~these~~financial ~~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 6 – 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 a $2,500 and $0 allowance for doubtful accounts as of December 31, 2015 and 2014, respectively.~~

68There was an allowance for doubtful accounts of $32,000 and $2,500 at December 31, 2016 and 2015, respectively.

Marketable Securities

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

Inventories

Inventories consist principally of light bulbs and are recorded at the lower of cost (first-in, first-out) or market.

Property, Equipment, and Furniture

Property, equipment, and furniture are carried at cost and additions or replacements are capitalized. The cost of equipment disposed of or retired and the related accumulated depreciation are eliminated from the accounts with any gain or loss included in operations.

Equipment, computers, software, and furniture are depreciated using the straight-line method over estimated useful lives that range from 3 to 7 years. ~~Property is depreciated using the straight-line method over an estimated useful life of 27.5 years.~~ Leasehold improvements are depreciated using the straight-line method over the shorter of the lease term or the estimated useful life of the asset. Expenditures for repairs and maintenance are charged to expense as incurred.

Real Estate Development

Costs that relate directly to real estate 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.

Acquisitions and 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 tangible and intangible assets acquired, the liabilities assumed, and any non-controlling interest at fair values at the transaction date. Transaction costs are expensed as incurred.

Acquisitions are initially recorded based on preliminary allocations of the purchase price and management’s assessment of fair values. The allocation process involves a considerable amount of subjective judgment and preliminary estimates of fair values are subject to adjustment as additional information is obtained and finalized, up to one year after the acquisition date.

See “Note 4 – Acquisitions”, “Note 16 - Intangible Assets”, and “Note 19 – Goodwill”.

Non-Controlling Interests

Ownership interests in a business organized as a legal entity are represented by shares or units. The income of the entity is allocated to owners based upon the ratio of their holdings to the total units or shares outstanding during the period. Capital contributions, distributions, and profits and losses are allocated to non-controlling interests in accordance with the terms of the operating agreement.

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.

Profits Interests

Specific second-tier subsidiaries of Enterprises 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, risk of capital loss, or opportunity for capital gain, they do not own non-controlling equity interests. Profits interest payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the consolidated balance sheet.

During the years ended December 31, 2015 and 2014, the Company included $2,478,413 and $6,363,520, respectively, in compensation and benefits representing the allocation of profits interests to Class B members.

Income Taxes

The Company is organized as a limited liability company under the laws of Minnesota and has elected to be taxed as a partnership. As such, it is not a taxable entity and no provision for federal or state income taxes has been made on the financial statements. ~~However,~~The ~~holders~~Company offiles ~~preferred~~income ~~units report distributions received on their individual~~ tax returns ~~while~~in ~~members~~U.S. ~~holding~~federal ~~common units~~and ~~report~~state ~~their~~jurisdictions. ~~proportionate~~The ~~shares~~years of2012 ~~taxable~~through ~~income~~2015 orremain ~~loss~~open ~~(which~~for ~~may~~examination by ~~vary substantially from~~ the ~~income~~IRS orand ~~loss~~state ~~reported in our consolidated statements of comprehensive income) on theirs~~agencies.

Noble is a Minnesota corporation, thus the Company has elected to use the taxes payable method. Under that method, income tax expense represents the amount of income tax Noble expects to pay based on the entity’s current year taxable income. TCPC files tax returns with the Canada Revenue Agency and the Tax and Revenue Administration of Alberta.51

70The Company recognizes 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 has no unrecognized tax positions.

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. Unit-Based ~~on evaluation of the Company’s~~ ~~tax positions, management believes all positions taken would be upheld under an examination.~~Compensation

The Company’s ~~federal~~expenses ~~and~~unit-based ~~state~~awards ~~tax~~pursuant ~~returns~~to ~~are~~ASC ~~potentially~~Topic ~~open~~718 toCompensation ~~examinations~~- ~~for~~Stock Compensation which requires that compensation cost at the ~~years~~grant ~~2012~~date ~~through~~fair ~~2015~~value ~~and~~of ~~its~~unit-based ~~Canadian~~awards be recognized over the requisite service period. The Company estimates ~~tax~~the ~~returns~~grant date fair value of unit-based awards issued based on a discounted cash flow model as the Company’s units are ~~potentially~~not publicly ~~open~~traded. toThe ~~examination~~discounted ~~for~~cash flow model requires the ~~years~~input ~~2012~~of ~~through~~highly ~~2015~~subjective assumptions, including projected growth and costs of capital. See “Note 14 – Ownership”.

New Accounting Pronouncements

In May 2014, the FASB issued a new revenue recognition standard, ASU 2014-09 Revenue from Contracts with Customers (Topic 606), that eliminated all industry-specific provisions and replaced all current U.S. GAAP guidance on the topic. The new standard provides a unified model to determine when and how revenue is recognized based on the core principle that recognition should depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the seller expects to be entitled. The Company was originally required to adopt the standard on January 1, 2017. In April 2015, the FASB proposed a one-year deferral of the effective date for the standard and the deferral was adopted in August 2015. The Company is now required to adopt the standard on January 1, 2018. ~~Early application is not permitted.~~ The update may be applied using one of two methods, either 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. In addition, the FASB issued ASU 2016-08, ASU 2016-10, ASU 2016-12, ASU 2016-20 in March 2016, April 2016, May 2016 and December 2016, respectively, to provide interpretive clarifications on the new guidance in ASC Topic 606. We have performed a review of the requirements of the new revenue standard and are ~~currently~~monitoring ~~assessing~~the activity of the FASB and the transition resource group as it relates to specific interpretive guidance. During 2017 we will work through our adoption plan. This plan includes a review of transactions supporting each revenue stream to determine the impact of accounting treatment under ASC 606, evaluation of the method of adoption, and completing a rollout plan for implementation of the new standard onwith affected functions in our organization. Because of the ~~Company’s~~nature of the work that remains, at this time we are unable to reasonably estimate the impact of adoption on our consolidated financial statements. We plan to adopt the new guidance beginning January 1, 2018.

In August 2014, the FASB issued ASU 2014-15 Presentation of Financial Statements – Going Concern (Subtopic 205-40) regarding disclosures of uncertainties about an entity’s ability to continue as a going concern. Under GAAP, continuation of a reporting entity as a going concern is presumed as the basis for preparing financial statements unless and until the entity’s liquidation becomes imminent. Currently, there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures and the update provides such. The update applies to all entities, ~~are~~and is effective for the annual period ending after December 15, ~~2016~~ 2016 and for annual periods and interim periods thereafter. Early application is permitted. The Company isadopted ~~currently~~ASU ~~evaluating~~2014-15 in the ~~impact~~ fourth quarter of ~~ASU~~2016. ~~2014-15~~See on“Note ~~the~~1 ~~Company’s~~– ~~disclosures~~Organization and Description of Business”.

In February 2015, the FASB issued ASU 2015-02 Amendments to the Consolidation Analysis (“ASU 2015-02”), amending ASC 810 to improve the guidance by simplifying the requirements for consolidation and placing more emphasis on risk of loss when determining a controlling financial interest. ASU 2015-02 is effective for the annual period ending after December 15, 2015 and subsequent interim and annual periods with early adoption permitted. The adoption of ASU 2015-02 is not expected to have a material impact on the Company’s consolidated financial statements.52

In ~~April~~February 2015, the FASB issued ASU 2015-0302 ~~Interest~~Amendments –to ~~Imputation~~the ofConsolidation ~~Interest~~Analysis (~~Topic~~“ASU ~~835~~2015-02”), ~~simplifying the presentation~~amending ofASC ~~debt~~810 ~~issuance~~to ~~costs.~~improve ~~The~~the ~~new~~ guidance ~~requires~~by ~~that~~simplifying ~~debt issuance costs related to a recognized debt liability be presented in~~ the ~~balance~~requirements ~~sheet~~for asconsolidation aand ~~direct~~placing ~~deduction~~more ~~from~~emphasis ~~the~~on ~~carrying~~risk ~~amount~~ of ~~that~~loss ~~debt liability. The recognition and measurement guidance~~when ~~for~~determining ~~debt~~a ~~issuance~~controlling ~~costs~~financial ~~are not affected by the new guidance~~interest. ~~This~~ASU ~~guidance~~2015-02 is effective for the annual ~~and~~period ~~interim~~ending ~~periods beginning~~ after December 15, 2015, and subsequent ~~early~~interim ~~adoption~~and isannual ~~permitted~~periods ~~for~~with ~~financial~~early ~~statements~~adoption ~~that have not been previously issued~~permitted. The ~~Company expects~~adoption toof ~~adopt~~ ASU 2015-0302 indid ~~the first quarter of 2016 and such adoption is~~ not ~~expected to~~ have a material impact on the Company’s consolidated financial ~~position and disclosures~~statements.

71In April 2015, the FASB issued ASU 2015-03 Interest – Imputation of Interest (Topic 835) 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 retrospectively adopted ASU 2015-03 in the first quarter of 2016. As a result, the Company reclassified net deferred financing costs of $314,000 to long term debt at December 31, 2015.

In ~~July~~February ~~2015~~2016, the FASB issued ASU ~~2015~~2016-1102 ~~Inventory~~

Filing Compare · ASPIRITY HOLDINGS LLC