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TWIN CITIES POWER HOLDINGS, LLC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion should be read in conjunction with our consolidated financial statements, notes to those statements, Management's Discussion and Analysis of Financial Condition and Results of Operations from our 2013 Form 10-K, and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-Q under the heading "Forward-Looking Statements" located on page 8, "Item 1A - Risk Factors" of our 2013 Form 10-K, and the "Risk Factors" section beginning on page 10 of ourForm S-1. The risks and uncertainties described in this Form 10-Q, our 2013 Form 10-K, and our Form S-1 are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition, or results of operations could suffer if the risks set forth arerealized. Industry Background Electric power in commercial quantities, unlike other energy commodities such as coal or natural gas, cannot be stored - the supply must be produced or generated exactly when used or demanded by customers. Further, the laws of physics dictate that power flows within a network along the lines of least resistance, not necessarily where we may want it to go. These facts, coupled with the necessity of electricity in modern life, have obvious implications for market structures and regulations. Since 1978, the investor-owned portion of the industry has been undergoing a massive restructuring process with the passage of the Public Utilities Regulatory Policy Act. PURPA stimulated development of renewable energy sources and co-generation and laid the groundwork for deregulation and competition by opening wholesale power markets to non-utility producers for the first time. Today, the industry includes any entity producing, selling, distributing, or trading electricity. As of the end of 2012, utilities numbered over 2,100 and included investor-owned, publicly-owned, cooperative, and federal entities - investor-owned utilities accounted for more than 71% of the industry's revenues, unit sales, and customers. There were also about 110 non-utility power producers. Power marketers and retail energy providers do not own any generation, transmission, or distribution assets but buy and sell in wholesale and retail markets. Other wholesale market participants include banks, hedge funds, private equity firms, and trading houses Overall, according to EIA data for 2012 (the most recent available), the U.S. electric power industry generated and sold 3,695 GWh at retail (down 1.5% from 2011) for a little more than $363.6 billion (down 2.0%) to over 145 million residential, commercial, industrial, and transportation customers (up 0.5%). In 2012, the average U.S. retail electricity price was 9.84¢/kWh - residential customers paid 11.88¢/kWh, commercial users paid 10.09¢/kWh, and industrial and transportation consumers paid 6.70¢/kWh. 37 Electricity Prices Today, wholesale prices are subject to a federal regulatory framework focused on ensuring fair competition and reliability of supply. At the state level, under the traditional system which most states continue to employ, a vertically integrated utility is responsible for serving all consumers in a defined territory and customers are obligated to pay the regulated rate for their class of service. However, in a state with a restructured or "deregulated" market, i.e., one with retail choice, the generation, transmission, distribution, and retail marketing functions of the business are legally separated and consumer pricing is unbundled. Wholesale electricity prices are driven by supply and demand and actually change minute-by-minute. Near term demand is largely affected by the weather and consumer behavior while supply is driven by plant availability and fuel prices, particularly for natural gas as it is the fuel of choice for marginal generation requirements. In the longer term, retail electricity prices reflect supply-side factors such as fuel prices and availability, generation technologies, plant and line construction and maintenance costs, and capital costs. Demand-side factors include population growth, economic activity, and energy efficiency. Governmental policies and regulations with respect to energy and the environment affect both the supply of, and demand for, electricity. Wholesale prices are typically quoted as "on-peak", "off-peak", or "flat", and in dollars per megawatt-hour ($/MWh). Peak hours are generally the 16 hours ending 0800 (8:00 am) to 2300 (11:00 pm) on weekdays, except for the NERC holidays of New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. Off-peak periods are all NERC holidays and weekend hours plus the 8 weekday hours from the hour ending at 2400 (midnight) until the hour ending at 0700 (7:00 am). Each month in a calendar year has a different number of on- and off- peak hours, consequently, the flat price for a given month takes this into account. The flat price for a day is simply the average of the 24 hourly prices. Retail prices are quoted in cents per kilowatt-hour (¢/kWh). One of the unique aspects of ISO electricity markets 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 congestion component, and a loss component. 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 reduceline 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. 38 Wholesale Electricity Markets After PURPA, the Energy Policy Act of 1992 was the next major legislative step towards full deregulation of wholesale power markets. In 1996, FERC issued Orders 888 and 889, which allowed for energy to be scheduled across multiple power systems, and in 1999, FERC issued Order 2000 calling for electric utilities to form RTOs or ISOs to operate the nation's bulk power system. The intended benefits of ISOs include eliminating discriminatory access to transmission for all generators, improving operating efficiency, and increasing system reliability. ISOs are typically not-for-profit entities using governance models developed by FERC. To date, seven ISOs have been formed in the U.S. In the parts of the country where ISOs have not been established, including the southeast, southwest and northwest, active wholesale markets are still present, although they operate with different structures. In addition to controlling the physical flow of power within its area of responsibility via direction to generators operating within the ISO's footprint, many ISOs also operate wholesale markets for real-time and day-ahead energy, as well as for generating capacity and ancillary services required to ensure system reliability. [[Image Removed]] Trading activity in ISO markets is often characterized by the acquisition of electricity at a given location such as a node or hub and its delivery to another. "Virtual" or purely financial transactions settle in cash in an amount equal to the difference between the purchase and sale prices, while physical transactions are settled by the delivery of the electricity itself, but in either case, the ISO serves as the counter-party and central clearinghousefor all trades. 39 In addition to the markets operated by the ISOs, derivative contracts such as swaps, options, and futures keyed to a wholesale electricity price are traded over-the-counter and on regulated exchanges, including ICE, NGX, and CME. Derivative contracts are available for many terms and pricing points and always settle in cash with profit or loss determined by price movements in the underlying commodity, whether it be electricity or another energy commodity such as natural gas or crude oil. Retail Electricity Markets Historically, at the state level, electricity was a regulated market, where vertically-integrated utilities owned all or a major part of the bulk power and distribution infrastructure and were responsible for generating electricity or buying it from other producers and distributing it to homes and businesses. Regulated utilities are responsible for serving all consumers in their defined territory and customers are obligated to pay the regulated rate for their class of service. Neither provider nor consumer has a choice about who they do business with. In the 1990s, many states, particularly those in the Northeast and California where retail prices were historically among the highest in the country, began restructuring their electric power industries in an effort to bring the benefits of competition to retail customers. This new regulatory approach centered on deregulation of generation and retail marketing while continuing the traditional cost-of-service plan for transmission and distribution. [[Image Removed]] 40 Unbundling of consumer electric bills in restructured markets made many aware for the first time exactly what they were paying for. In general, the bills of retail electricity customers include numerous charges that can be classified into three major categories - generation, delivery, and governmental policy costs, such as universal service, lifeline service, energy efficiency programs, and sales and use taxes. On average between 2000 and 2012, energy and delivery accounted for about 67% and 33%, respectively, of the average retail price excluding policy costs. Of course, these percentages fluctuate from year to year and state to state, primarily due to wholesale energy market conditions, weather, and state rules. The regulated portions of formerly vertically-integrated utilities, now generally known as electric or local distribution companies ("EDCs" or "LDCs") are responsible for delivering power, billing consumers, and resolving any service issues, but customers can shop around and buy power from any licensed supplier or broker doing business in the state, hence "retail choice". Today, 15 years after Massachusetts and Rhode Island became the first states to effectively implement choice in 1998, 20 jurisdictions have some form of choice. However, it is important to note that not all consumers in choice jurisdictions are able to select their electricity supplier as they are served by public or cooperative utilities. Nonetheless, in the 14 areas where all rate classes have choice there are almost 24 million residential and over 2.8 million non-residential customers using about 353,000,000 MWh annually. Overall, we believe that choice is proving to be a boon for consumers. According to an analysis of data from the EIA, between 2000 and 2012 retail rates for all customer sectors in states with restructured retail markets increased by only 12.0% compared with a 34.9% increase in states that rely on regulated utilities. 41 Company Overview The following discussion should be read in conjunction with our consolidated financial statements, notes to those statements, and the other financial information appearing in this report. The risks and uncertainties described are not the only ones facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition, or results of operations could suffer if the risks set forth are realized. Through its wholly-owned subsidiaries, TCPH trades financial and physical electricity contracts in North American wholesale markets regulated by FERC and operated by ISOs and RTOs, trades energy derivative contracts on exchanges regulated by the CFTC, including ICE, NGX, and CME, provides electricity supply services to retail customers in certain states that permit retail choice, and is engaged in certain real estate development activities. Consequently, the Company has three major business segments used to measure its activity - wholesale trading, retail energy services, and real estate development. The following shows our organizational structure as of June 30, 2014 (active entities only): [[Image Removed]] Key:Orange - Holding Company; Green - Wholesale Energy Trading; Light Blue - Retail Energy Services; Gray - Real Estate Development Wholesale Trading In general, the Company's trading activities are characterized by the acquisition of electricity or other energy-related commodities at a given location and its delivery to another. "Financial" transactions settle in cash in an amount equal to the difference between the purchase and sale prices, while "physical" transactions are settled by the delivery of the commodity. ISO-traded financial contracts are also known as "virtual" trades, are outstanding overnight, and settle the next day. The Company also trades electricity and other energy derivatives on ICE, NGX, and CME and may hold an open interest in these contracts overnight or longer. 42 Retail Energy Services On June 29, 2012, TCP acquired certain assets and the business of Community Power & Utility LLC, a retail energy supplier serving residential and small commercial markets in Connecticut. The business was re-named TSE, and beginning on July 1, 2012, the Company began selling electricity to retail accounts. During late 2012 and early 2013, TSE applied for retail electricity supplier licenses for the states of Massachusetts, New Hampshire, and Rhode Island which were issued on various dates in 2013. On January 2, 2014, the Company acquired DEG, a retail energy business licensed by the states of Maryland, New Jersey, Pennsylvania, and Ohio. Consequently, the retail markets in which the Company expects to compete in 2014 include at least the following states: Connecticut, Maryland, Massachusetts, New Hampshire, New Jersey, Pennsylvania, Ohio, and Rhode Island; however, projected margins in specific states and utility service territories will ultimately determine where the Company will deploy its retail marketing resources and obtain customers. Our customer base consists largely of residential consumers with a few small commercial accounts. We primarily use direct marketing strategies to sell our services and our customers may typically cancel their contracts at any time. Real Estate Development On October 23, 2013, the Company formed Cyclone as a wholly-owned subsidiary to take advantage of certain perceived investment opportunities present in the residential real estate market in the southern portion of the Minneapolis-St. Paul metropolitan area. Specifically, Cyclone intends to acquire and develop land for resale, either as improved sites for construction of single- and multi-family homes or as completed dwellings. 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, we are exposed to volatility in the cost of energy acquired for sale to customers, and as a result, we use derivatives to hedge or reduce this variability. Our retail operations follow ASC 815, Derivatives and Hedging ("ASC 815") guidance that permits "hedge accounting". To qualify for hedge accounting, the relationship between the "hedged item" (say power purchases for a given delivery zone) and a derivative used as a "hedging instrument" (say, a swap contract for future delivery of electricity at a related hub), must meet extensive documentation requirements and hedge effectiveness and ineffectiveness must be assessed and measured on an on-going basis. For these derivatives "designated" as cash flow hedges, the effective portion of any change in the hedging instrument's fair value is recorded as other comprehensive income and deferred until the change in value of the hedged item is recognized in earnings. Our risk management policies also permit the use of undesignated derivatives which we refer to as "economic hedges". For an undesignated economic hedge, all changes in the derivative financial instrument's fair value are recognized currently in revenues. 43 For the three and six months ended June 30, 2014 and 2013, financial and virtual electricity represented 100% of our total trading volume in FERC-regulated markets, that is, we traded no physical power during these periods in our wholesale segment. The table below details our open derivative contracts held for trading purposes, as undesignated, economic hedges by our retail segment, and as cash flow hedges by our retail segment as of June 30, 2014: Open Derivative Contracts As of June 30, 2014 Fair Value Segment and Delivery Final Energy contract type Hub or zone period settlement (MWh) Asset Liability Wholesale Trading Electricity MISO Indiana future Hub peak daily daily (2,400 ) $ - $ 2,200 Electricity ERCOT North future zone peak daily daily 800 120 - Electricity PJM West Hub future peak daily daily 20,000 66,480 - Electricity Alberta ext future off peak Jul 2014 8/4/14 1,240 - 47,120 Electricity Alberta ext future off peak Oct 2014 11/4/14 33,480 - 1,227,042 Electricity Alberta ext future off peak Oct 2014 11/4/14 66,960 1,714,176 - Electricity Alberta ext future off peak Nov 2014 12/4/14 2,400 - 81,600 Electricity Alberta ext future off peak Nov 2014 12/4/14 4,800 74,400 - Subtotals, wholesale trading segment 127,280 1,855,176 1,357,962 Retail Energy Services - Economic Hedges Electricity futures PJM West Hub Q3 2014 various 4,296 2,803 1,440 Electricity NYISO Zone G futures and and PJM West options Hub Q4 2014 various 47,615 70,674 91,110 Electricity futures PJM West Hub Q1 2015 various 10,795 83,652 - Electricity futures PJM West Hub Q2 2015 various 10,920 4,736 40,514 Electricity futures PJM West Hub Q3 2015 various 11,040 13,624 25,762 Electricity futures PJM West Hub Q4 2015 various 16,545 8,888 47,429 Subtotals, retail energy services segment, economic hedges 101,211 184,376 206,255 Retail Energy Services - Designated Cash Flow Hedges Electricity ISO-NE Mass futures Hub and Connecticut Zone Q3 2014 various 23,600 116,294 70,456 Electricity ISO-NE Mass futures Hub Q4 2014 various 10,845 224,274 40,308 Electricity ISO-NE Mass futures Hub Q2 2015 various 14,280 10,824 69,642 Electricity ISO-NE Mass futures Hub Q3 2015 various 18,480 75,480 132,268 Subtotals, retail energy services segment, cash flow hedges 67,205 426,872 312,674 Totals 295,696 $ 2,466,424 $ 1,876,891 44 The table below details our open derivative contracts held for trading purposes, as undesignated, economic hedges by our retail segment, and as cash flow hedges by our retail segment as of December 31, 2013: Open Derivative Contracts Held for Trading or as Economic Hedges As of December 31, 2013 Fair Value Segment and Delivery Final Energy contract type Hub or zone period settlement (MWh) Asset Liability Wholesale Trading Electricity PJM West Hub future peak Dec 2013 1/3/14 4,000 $ - $ 17,240 Electricity PJM West Hub future peak Dec 2013 1/3/14 16,800 - 34,608 Electricity PJM West Hub future peak Dec 2013 1/3/14 800 - 400 Electricity PJM West Hub future peak daily 1/6/14 1,600 - 3,200 Electricity AESO ext future peak Feb 2014 3/4/14 40,320 - 596,137 Electricity AESO ext off future peak Feb 2014 3/4/14 19,040 614,592 - Electricity AESO ext off future peak Mar 2014 4/5/14 1,240 - 35,571 Subtotals, wholesale trading segment 83,800 614,592 687,156 Retail Energy Services - Economic Hedges Electricity ISO-NE Mass futures Hub, NYISO Zone G, and PJM West Hub Q1 2014 various 22,200 60,226 36,724 Electricity futures PJM West Hub Q2 2014 various 5,120 1,932 7,660 Electricity futures PJM West Hub Q3 2014 various 5,120 40,856 4,872 Electricity futures PJM West Hub Q3 2014 various 5,120 - 21,416 Subtotals, retail energy services segment, economic hedges 37,560 103,014 70,672 Retail Energy Services - Designated as Cash Flow Hedges Electricity ISO-NE Mass futures Hub Q1 2014 various 12,200 289,338 - Electricity ISO-NE Mass futures Hub Q2 2014 various 8,560 2,436 24,564 Electricity ISO-NE Mass futures Hub Q3 2014 various 5,120 11,588 251 Electricity ISO-NE Mass futures Hub Q4 2014 various 6,880 113,948 35,880 Subtotals, retail energy services segment, cash flow hedges 32,760 $ 417,310 $ 60,695 Totals 154,120 $ 1,134,916 $ 818,523 45 Results of Operations Three Months Ended June 30, 2014 and 2013 The following table sets forth selected financial data for the periods indicated, which has been derived from the consolidated financial statements included in this report: For The Three Months Ended June 30, 2014 2013 Increase (decrease) Dollars inthousands Dollars Percent Dollars Percent Dollars Percent Revenue Wholesale trading revenue, net $ 1,843 45.3% $ 7,792 83.0% $ (5,949 ) -76.3% Retail electricity revenue 2,227 54.7% 1,598 17.0% 629 39.4% Net revenue 4,070 100.0% 9,390 100.0% (5,320 ) -56.7% Operating costs & expenses Cost of retail electricity sold 1,678 41.2% 1,598 17.0% 80 5.0% Retail sales and marketing 23 0.6% - 0.0% 23 na Compensation and benefits 2,288 56.2% 2,778 29.6% (490 ) -17.6% Professional fees 1,365 33.5% 2,573 27.4% (1,208 ) -46.9% Other general & administrative 838 20.6% 699 7.4% 139 19.9% Trading tools & subscriptions 336 8.2% 263 2.7% 73 27.8% Total operating expenses 6,528 160.4% 7,911 84.2% (1,383 ) -17.5% Operating income (loss) (2,458 ) -60.4% 1,479 15.8% (3,937 ) -266.2% Interest expense (514 ) -12.6% (360 ) -3.8% (154 ) 42.8% Interest income 43 1.1% 8 0.0% 35 437.5% Loss on foreign currency exchange (261 ) -6.4% (1 ) 0.0% (260 ) 26000.0% Other income 3 0.1% - 0.0% 3 na Other expense, net (730 ) -18.0% (353 ) -3.8% (377 ) 106.7% Income (loss) before income taxes (3,188 ) -78.4% 1,126 12.0% (4,314 ) -383.1% Income tax provision (benefit) - -0.1% 9 0.1% (9 ) -100.0% Net income (loss) (3,188 ) -78.3% 1,117 11.9% (4,305 ) -385.4% Preferred distributions (137 ) -3.4% (137 ) -1.5% - 0.0% Net income (loss) attributable to common $ (3,325 ) -81.7% $ 980 10.4% $ (4,305 ) -439.2% 46 Wholesale trading revenue, net:Generally, our greatest opportunities for profitable trades occur during periods of market turbulence, when the forecast for supply or demand is more likely to be inaccurate. When demand for energy is relatively stable, price variations tend to be small or non-existent. During periods of market turbulence, prices tend to be volatile, which give our traders the opportunity to take advantage of such volatility. In our wholesale trading business, we record revenues based upon changes in the fair values of the contracts we trade, net of costs. The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of instruments that remain open at a balance sheet date represent unrealized gains or losses. Our primary costs in generating revenue are compensation of our energy traders as well as the interest expense of obtaining the capital necessary to post collateral. 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 and whether or not we are buying or selling. According to NOAA data, for the three months ended June 30, 2014, heating degree-days for the U.S. were 482 or 6% below the figure for the same period in 2013 of 512 and 2% below the 30 year normal of 493. Cooling degree-days during the second quarter of 2014 totaled 387 compared to 370 in 2013 and a normal of 376, making the quarterly period about 5% warmer than last year and about 3% warmer than normal. During the second quarter of 2014, the Henry Hub natural gas spot price averaged $4.60/MCF, 15% above 2013's $4.01 mark and 23% above the 5 year average price of $3.74. Supplies of gas during 2014 were adequate. Weekly storage levels averaged 1,308 BCF or 37% less than in 2013's level of 2,084 BCF and 41% lower than the 5 year average of 2,225. Three Months Ended June 30, Increase (decrease) Units This year vs last year This year vs LTA 2014 2013 LTA (1) Units Percent Units Percent U.S. Weather Heating degree-days 482 512 493 (30 ) -6% (11 ) -2% Cooling degree-days 387 370 376 17 5% 11 3% Avg temperature (°F) 60.8°F 60.3°F 61.7°F 0.5°F 1% -0.8°F -1% Natural Gas Henry Hub spot price ($/MCF) 4.60 4.01 3.74 0.59 15% 0.86 23% Working gas in underground storage, Lower 48 states, EIA weekly estimates (BCF) 1,308 2,084 2,225 (776 ) -37% (917 ) -41% __________ 1 - "LTA" abbreviates long term average. For weather data, the 30 year period is 1984-2013 and for natural gas the 5 year period is 2009-2013. 47 The average for the PJM West Peak price during the three months ended June 30, 2014 was $50.48/MWh with a standard deviation of $7.95 resulting in a coefficient of variation of 16%, compared to $44.04/MWh, $7.40, and 17% for the same period in 2013. As shown by the table below, price levels and volatility were generally about the same in the 2014 period as compared to 2013. Three Months Ended June 30, Increase (decrease) PJM West Hub Peak Day Ahead 2014 2013 Units Percent Price ($/MWh) Average 50.48 44.04 6.44 15% Maximum 80.65 76.88 3.77 5% Minimum 37.83 33.22 4.61 14% Standard deviation 7.95 7.40 0.56 8% Coefficient of variation (stdev ÷ avg) 16% 17% -1% -6% Daily percentage changes Average 1.0% 0.8% 0.2% 27% Maximum 37.3% 41.0% -3.7% -9% Minimum -30.9% -46.6% 15.7% -34% Standard deviation 12.5% 11.9% 0.7% 6% Number of days Up 10% or more 18 12 6 50% Between 10% up and 10% down 33 42 (9 ) -21% Down 10% or more 13 10 3 30% During the second quarter, we hired eight new traders, bringing the total to 27 as of June 30, 2014. We also began trading financial transmission rights ("FTRs") in the MISO market. Largely as a result of these factors, primarily the lack of market turbulence and price volatility, for the three months ended June 30, 2014, net trading revenue decreased by $5,949,000 or 76.3% to $1,843,000 compared to $7,792,000 for the same period in 2013. 48 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 the second quarter of 2014, 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 to reduce our exposure to higher costs. Consequently, the gain on these contracts is reported as "wholesale trading revenue, net". For the three months ended June 30, 2014 and 2013, we recorded wholesale trading revenues of $238,000 and $0, respectively, in our retail energy services segment. During the second quarter of 2014, exclusive of these gains on economic hedges, we recognized retail sales revenue of $2,227,000 compared to $1,598,000 for 2013, up 39%, principally as a result of increased prices, an increased customer count, and the recording of additional retail sales of $465,000 due to a change in estimate. See also "Note 16 - Segment Information" to our Consolidated Financial Statements. The following table summarizes the key operating statistics of our retail business. For/At Three Months Ended June 30, Increase (decrease) Key Operating Statistics 2014 2013 Units Percent Revenues ($000s) 2,227 1,598 629 39.4% Unit sales (MWh) 20,044 21,365 (1,321 ) -6.2%Average retail price (¢/kWh) 11.11 7.48 3.63 48.5% Customers receiving service, EoP 9,808 9,281 527 5.7% New customer sign-ups, net of (drops) 3,865 2,081 1,784 85.7% Avg daily sign-ups (drops) 42 23 20 85.7% Real estate development, net: Revenues from real estate developments, if any, are recognized at the time of sale closing if all significant conditions are satisfied, including adequate down payment, reasonable assurance of collectability of any notes received, and completion of other contract requirements. Recognition of all or part of the revenue is deferred if any significant conditions are not satisfied. Costs that relate directly to development projects are capitalized and allocated using the specific identification method. Land acquisition, improvements, and holding costs, including real estate taxes and interest are capitalized while a development is in progress. Interest expense, if any, is capitalized based on specific identification of notes payable issued to finance specific assets under development. Once development on a project has been completed and sales have begun, remaining inventory is recorded at the lower of cost or market. Development costs are charged to cost of sales when the related revenue is recognized or when a development is abandoned. During the three months ended June 30, 2014, the Company recorded no revenue or income but capitalized a total of $34,226 of costs associated with its real estate development activities. 49 Costs of retail electricity sold:Our costs of electricity sold includes the cost of purchased power, EDC service fees, renewable energy certificates, bad debt expense, and gains net of losses and commissions on derivative contracts used to hedge power purchase costs. For the three months ended June 30, 2014, the Company purchased electricity sold to retail customers in ISO-NE's and PJM's wholesale markets and from certain other wholesale suppliers. The Company is required to maintain cash deposits in separate accounts to meet our wholesale energy vendors' financial assurance requirements to purchase energy, ancillary services, and capacity which amount is included in "cash in trading accounts". During the second quarter of 2014, we fixed part of the cost of the energy sold to our customers using 9,283 MWh of forward physical purchases and 16,040 MWh of derivatives designated as cash flow hedges. For the three months ended June 30, 2014 and 2013, our designated hedges had the effect of increasing cost of retail electricity sold by $152,956 and $172,460, respectively. As shown by the Open Derivative Contracts table on page 44, as of June 30, 2014, we had designated 67,205 MWh of electricity futures as hedges against the cost of expected 2014 and 2015 electricity purchases. $114,198, representing the net gain on the effective portion of the hedge, was deferred in accumulated other comprehensive income and $229,804 and $(115,606) of this amount is expected to be reclassified to cost of retail electricity sold by December 31, 2014 and 2015, respectively. For the three months ended June 30, 2014, our cost of retail electricity sold, net of gains on designated hedges, increased by $80,000 or 5.0% to $1,678,000 compared to $1,598,000 for the same period in 2013. Compensation and benefits:Salaries, wages, and related expenses such as employee benefits and payroll taxes consist primarily of base and incentive compensation paid to our administrative officers, energy traders, and other employees. Even though we hired additional traders in the second quarter of 2014, for the three months ended June 30, 2014, salaries, wages, and related costs decreased by $490,000 or 17.6% to $2,288,000 compared to $2,778,000 for the same period in 2013. A substantial portion of our personnel expense is directly related to the revenue we record, since our traders' compensation is tied to revenue production. Professional fees: Professional fees consist of legal expenses, audit fees, tax compliance reporting service fees, and other fees paid for outside consulting services. For the second quarter of 2014, professional fees decreased by $1,208,000 or 46.9% to $1,365,000 compared to $2,573,000 for the same period in 2013, primarily because of higher consulting fees incurred in the comparable 2013 period. 50 Other general and administrative:Other general and administrative expenses consist of rent, depreciation, amortization, travel, outside retail marketing and customer service costs, and all other direct office support expenses. For the three months ended June 30, 2014, these costs increased by approximately $139,000 to $838,000 compared to $699,000 for the same period in 2013. The increase was primarily related to an increase in amortization expense by $59,000 to $139,000 from $80,000 due to the amortization of certain intangible assets acquired in connection with the DEG acquisition. Also, with the DEG acquisition the entity has accumulated its own general and administrative expenses that did not exist in the same period in 2013. The Company also continues to incur marketing costs and administrative expenses associated with the Notes Offering. 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 period ended June 30, 2014, trading tools and subscriptions expense increased by $73,000 or 27.8% to $336,000 compared to $263,000 for the same period in 2013, primarily due to the acquisition of DEG. Other income (expense): Other expense, net of other income, increased by $377,000 to $730,000 for 2014 compared to $353,000 for 2013. As the principal component of other expense, interest expense increased by $154,000 to $514,000 for the three months from $360,000 during the same period in 2013. The increase was attributed primarily to an increase in outstanding debt of $1,909,000 for the three months ended June 30, 2014 compared to an increase of $1,535,000 for the three months ended June 30, 2013. Preferred distributions:During the second quarters of 2014 and 2013, we distributed $137,000 to preferred unit holders. 51 Six Months Ended June 30, 2014 and 2013 The following table sets forth selected financial data for the periods indicated, which has been derived from the consolidated financial statements included in this report: For The Six Months Ended June 30, 2014 2013 Increase (decrease) Dollars in thousands Dollars Percent Dollars Percent Dollars Percent Revenue Wholesale trading revenue, net $ 28,865 84.9% $ 14,589 82.8% $ 14,276 97.9% Retail electricity revenue 5,127 15.1% 3,035 17.2% 2,092 68.9% Net revenue 33,991 100.0% 17,624 100.0% 16,367 92.9% Operating costs & expenses Cost of retail electricity sold 6,267 18.4% 3,282 18.6% 2,985 91.0% Retail sales & marketing 151 0.4% - 0.0% 151 na Compensation & benefits 12,923 38.0% 6,378 36.2% 6,545 102.6%Professional fees 2,498 7.3% 3,500 19.9% (1,002 ) -28.6% Other general & administrative 1,668 4.9% 1,331 7.6% 337 25.3% Trading tools & subscriptions 629 1.9% 486 2.8% 143 29.4% Total operatingexpenses 24,137 71.0% 14,977 85.0% 9,160 61.2% Operating income (loss) 9,854 29.0% 2,647 15.0% 7,207 272.3% Interest expense (982 ) -2.9% (709 ) -4.0% (273 ) 38.4% Interest income 55 0.2% 16 0.1% 39 243.8% Loss on foreign currency exchange (261 ) -0.8% - 0.0% (261 ) na Other income 3 0.0% - 0.0% 3 na Other income (expense), net (1,184 ) -3.5% (693 ) -3.9% (491 ) 70.9% Income (loss) before income taxes 8,670 25.5% 1,954 11.1% 6,716 343.7% Income tax provision (benefit) - 0.0% 9 0.1% (9 ) -100.0%Net income (loss) 8,670 25.5% 1,945 11.0% 6,725 345.8% Preferred distributions (275 ) -0.8% (275 ) -1.6% - 0.0% Net income (loss) attributable to common $ 8,395 24.7% $ 1,670 9.5% $ 6,725 402.7% Wholesale trading revenue, net:Market conditions in the first half of 2014 were exceptionally favorable for us during the first quarter and adverse in the second. We successfully capitalized on the exceptional market volatility brought about by the "polar vortex", which largely disappeared in the April to June period. According to NOAA data, for the six months ended June 30, 2014, heating degree-days for the U.S. were 2,974 or 7% above the figure for the same period in 2013 of 2,767 and 12% above the 30 year normal of 2,664. Cooling degree-days during the six months ended June 30, 2014 totaled 418 compared to 402 in 2013 and a normal of 411, making the year the year to date about 1% cooler than last year and about 4% cooler than normal. During the first six months of 2014, the Henry Hub natural gas spot price averaged $4.88/MCF, 30% above 2013's $3.76 mark and 27% above the 5 year average price of $3.85. Supplies of gas during 2014 were adequate. Weekly storage levels averaged 1,470 BCF or 35% less than in 2013's level of 2,253 and 35% lower than the 5 year average of 2,258. 52 Six Months Ended June 30, Increase (decrease) Units This year vs last year This year vs LTA 2014 2013 LTA (1) Units Percent Units Percent U.S. Weather Heating degree-days 2,974 2,767 2,664 207 7% 310 12% Cooling degree-days 418 402 411 16 4% 7 2% Avg temperature (°F) 47.6°F 48.1°F 49.6°F -0.5°F -1% -2.0°F -4% Natural Gas Henry Hub spot price ($/MCF) 4.88 3.76 3.85 1.12 30% 1.03 27% Working gas in underground storage, Lower 48 states, EIA weekly estimates (BCF) 1,470 2,253 2,258 (782 ) -35% (788 ) -35% ________ 1 - "LTA" abbreviates long term average. For weather data, the 30 year period is 1984-2013 and for natural gas the 5 year period is 2009-2013. The average for the PJM West Peak price during the six months ended June 30, 2014 was $76.28/MWh with a standard deviation of $73.43 resulting in a coefficient of variation of 96%, compared to $42.57/MWh, $8.32, and 20% for the same period in 2013. As shown by the table below, price levels and volatility were generally much higher in the 2014 period as compared to 2013. Six Months Ended June 30, Increase (decrease) PJM West Hub Peak Day Ahead 2014 2013 Units Percent Price ($/MWh) Average 76.28 42.57 33.72 79% Maximum 655.75 77.67 578.07 744% Minimum 37.15 29.70 7.45 25% Standard deviation 73.43 8.32 65.11 783% Coefficient of variation (stdev ÷ avg) 96% 20% 77% 393% Daily percentage changes Average 4.9% 0.7% 4.1% 550% Maximum 200.3% 41.0% 159.3% 388% Minimum -78.1% -46.6% -31.6% 68% Standard deviation 34.7% 11.8% 22.8% 193% Number of days Up 10% or more 40 25 15 60% Between 10% up and 10% down 50 81 (31 ) -38% Down 10% or more 37 21 16 76% Largely as a result of these factors, for the six months ended June 30, 2014, net trading revenue increased by $14,276,000 or 97.9% to $28,865,000 compared to $14,589,000 for the same period in 2013. Retail electricity sales:During the six months ended June 30, 2014, we recognized retail sales revenue of $5,127,000 compared to $3,035,000 for 2013, up 68.9%, principally as a result of increases in the amount of energy used per customer, increased prices, an increased customer count, and a change in revenue estimate. For the six month period ended June 30, 2014, 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 to reduce our exposure to higher costs. Consequently, the gain on these contracts is reported as "wholesale trading revenue, net". For the six month period ended June 30, 2014 and 2013, we recorded wholesale trading revenues of $2,050,478 and $0, respectively, in our retail energy services segment. 53 The following table summarizes the key operating statistics of our retail business for the first half of 2014. For/At Six Months Ended June 30, Increase (decrease) Key Operating Statistics 2014 2013 Units Percent Revenues ($000s) 5,127 3,035 2,092 68.9% Unit sales (MWh) 47,203 40,464 6,739 16.7% Average retail price (¢/kWh) 10.86 7.50 3.36 44.8% Customers receiving service, EoP 9,805 9,281 524 5.6% New customer sign-ups, net of (drops) 1,328 5,446 (4,118 ) -75.6% Avg daily sign-ups (drops) 7 30 (23 ) -75.6% Real estate development, net: During the six months ended June 30, 2014, the Company recorded no revenue or income but capitalized a total of $56,505 of costs associated with its real estate development activities. Costs of retail electricity sold:During the six months ended June 30, 2014, we fixed part of the cost of the energy sold to our customers using 9,283 MWh of forward physical purchases and 31,875 MWh of derivatives designated as cash flow hedges. For the six months ended June 30, 2014 and 2013, our designated hedges had the effect of decreasing cost of retail electricity sold by $418,549 and $253,243, respectively. Principally as a result of increases in the amount of energy used per customer, increased costs, and an increase customer count, for the six months ended June 30, 2014, our cost of retail electricity sold, net of gains on designated hedges, increased by $2,985,000 or 91.0% to $6,267,000 compared to $3,282,000 for the same period in 2013. Compensation and benefits:For the six months ended June 30, 2014, salaries, wages, and related costs increased by $6,545,000 or 102.6% to $12,923,000 compared to $6,378,000 for the same period in 2013. Our personnel expense is directly related to the revenue we record, since our traders' compensationis tied to revenue production. Professional fees: For the six months ended June 30, 2014, professional fees decreased by $1,002,000 to $2,498,000 compared to $3,500,000 for the same period in 2013, primarily due to higher consulting fees incurred in the comparable2013 period. Other general and administrative:For the six months ended June 30, 2014, these costs increased by approximately $337,000 to $1,668,000 compared to $1,331,000 for 2013. The increase was primarily related to an increase in amortization expense by $129,000 to $289,000 from $160,000 due to the amortization of certain intangible assets acquired in connection with the DEG acquisition. In addition, DEG incurred an additional $50,000 of general and administrative expenses in the period that were not present in 2013. Finally, the Company donated $50,000 and $0 to charities during the periods ending June 30, 2014 and 2013, respectively, and continues to incur marketing costs and administrative expenses associated with the Notes Offering. Trading tools and subscriptions:For the first half ended June 30, 2014, trading tools and subscriptions expense increased by $143,000 or 29.4% to $629,000 compared to $486,000 for the same period in 2013, primarily due to the acquisition of DEG. 54 Other income (expense):Other expense, net of other income, increased by $491,000 to $1,184,000 for the first half of 2014 compared to $693,000 for the same period in 2013. As the principal component of other expense, interest expense increased by $273,000 to $982,000 for the year to date from $709,000 during 2013. The increase was attributed primarily to an increase in outstanding debt of $7,417,000 for the six month period ended June 30, 2014 compared to $2,060,000 for the six month period ended June 30, 2013. Preferred distributions:During the six months ended June 30, of 2014 and 2013, we distributed $275,000 to preferred unit holders. Liquidity, Capital Resources, and Cash Flow In our wholesale trading business, we require a significant amount of cash to maintain collateral with the trading markets in which we operate, which in turn allows us to trade in those markets and generate revenues. With respect to our retail operation, in addition to collateral posted with ISOs that allow us to acquire power for our customers, we are also required to fund accounts receivable as well as margin requirements associated with hedges. We are generally required to pay for power every 4 days or so, while our average collection period on receivables is 40 to 45 days. As such, our capital is largely invested in trading accounts and deposits and receivables. Our capital expenditure requirements are nominal, being limited to computer and office equipment, software, and office furniture. Therefore, in any given reporting period, the amount of cash consumed or generated will primarily be due to changes in working capital. Historically, our capital requirements have been funded by notes payable and operating profits and we are dependent on cash on hand, cash-flow positive operations, and additional financing to service our existing obligations. Should we incur significant losses from operations within a short period, we might be forced to cover such payments by reducing the balances in our trading accounts, which would have a detrimental effect on the Company. We are taxed as a partnership for income tax purposes which means that we do not pay any income taxes. All of our income (or loss) for each year is allocated among holders of our common units who are then personally responsible for the tax liability associated with such income. Our Member Control Agreement provides for distributions of cash to these members based upon their respective ownership interests in the amount necessary to permit the member who is in the highest income tax bracket to pay all state and federal taxes on our net income allocated to such member. The decision to make distributions other than tax distributions to holders of our common units and required distributions to holders of preferred units is at the discretion of our Board of Governors (the "Board") and depends on various factors, including our results of operations, financial condition, capital requirements, contractual restrictions, outstanding indebtedness, investment opportunities, and other factors considered by the Board to be relevant. The indenture governing our Notes prohibits us from paying distributions to our members if there is an event of default with respect to the Notes or if payment of the distribution would result in an event of default. The indenture also prohibits our Board from declaring or paying any distributions other than tax distributions if, in the reasonable determination of the Board, the Company would have insufficient cash to meet anticipated Note redemption or repayment obligations. While we believe we have sufficient cash on hand, coupled with anticipated cash generated from operating activities and the anticipated proceeds from our Notes Offering to meet our operating cash requirements for at least the balance of 2014, we regularly evaluate other potential sources of capital, which may include sourcing additional financing in the form of debt in order to provide added flexibility to support our working capital needs and reduce our overall costs of borrowing. In addition, the Company currently has sufficient liquidity for its operating requirements and expects to use a portion of its available cash to finance additional retail energy expansion and acquisitions, and may also examine a variety of potential investments for its excess cash, which could include equities, real estate, and debt instruments. There can be no assurance that these investments will prove to be profitable. 55 The following table is presented as a measure of our liquidity and capital resources as of the dates indicated: At June 30, 2014 December 31, 2013 Increase (decrease)Dollars in Percent of Percent of thousands Dollars total assets Dollars total assets Dollars Percent Liquidity Cash - unrestricted $ 2,976 10.4% $ 3,190 18.2% $ (214 ) -6.7% Cash in trading accounts 17,540 61.1% 10,484 59.7% 7,056 67.3% Accounts receivable - trade 2,122 7.4% 1,315 7.5% 807 61.4% Total liquid assets 22,638 78.9% 14,989 85.4% 7,649 51.0% Total assets $ 28,688 100.0% $ 17,562 100.0% $ 11,126 63.4% Capital Resources Current $ 7,152 24.9% $ 5,123 29.2% $ 2,029 39.6% Long term 6,545 22.8% 5,062 28.8% 1,483 29.3% Total debt 13,697 47.7% 10,185 58.0% 3,512 34.5% Series A preferred 2,745 9.6% 2,745 15.6% - 0.0% Common 7,359 25.7% 2,003 11.4% 5,356 267.4% Total equity 10,104 35.2% 4,748 27.0% 5,356 112.8% Total capitalization $ 23,801 82.9% $ 14,933 84.9% $ 8,868 59.4% The table below summarizes our primary sources and uses of cash for the six months ended June 30, 2014 and 2013 as derived from the statements of cash flows included in this Form 10-Q. For the Six Months Ended June 30, Increase (decrease) Dollars in thousands 2014 2013 Dollars Percent Net cash provided by (used in): Operating activities $ 3,352 $ 3,926 $ (574 ) (14.6)% Investing activities (3,722 ) (182 ) (3,540 ) 1945.1 % Financing activities (63 ) 298 (361 ) (121.1)% Net cash flow (433 ) 4,042 (4,475 ) (110.7)% Effect of exchange rate changes on cash 218 (161 ) 379 135.4 % Cash - unrestricted: Beginning of period 3,190 772 2,418 313.2 % End of period $ 2,975 $ 4,652 $ (1,678 ) (36.0)% At June 30, 2014, our debt totaled $13,697,000 compared to $10,185,000 as of the prior year end. For the six months ended June 30, 2014, we generated $3,352,000 of cash from operating activities and used $3,722,000 for investments in property, equipment, furniture, land held for development, certain securities, and restricted cash. Financing activities required net cash of $63,000, including a net increase in debt of $3,284,000 and the payment of $3,348,000 in distributions. Of the total distribution amount, $275,000 was paid to the holder of our preferred units and $3,073,000 was paid to our common unit-holders. 56 Financing In February 2012, we executed a $25,000,000 Futures Risk-Based Margin Finance Agreement for the benefit of CEF (the "Margin Line" and the "Margin Agreement", respectively) with ABN AMRO. The Margin Agreement provides an uncommitted revolving line of credit for which CEF pays a monthly commitment fee. Loans under the Margin Agreement are secured by all balances in CEF's trading accounts with ABN AMRO, are payable on demand, and bear interest at an annual rate equal to 1.00% in excess of the Federal Funds Target Rate, or approximately 1.25%. Under the Margin Agreement, the Company is also subject to certain reporting, affirmative, and negative covenants, including maintenance of minimum account net liquidating equity, a maximum loan ratio as defined, and minimum consolidated tangible net worth as defined. The Margin Agreement was amended on May 31, 2013 to reduce the credit line to $15,000,000, the commitment fee to $25,000 per month, and the covenant with respect to net liquidating equityas defined to $1,500,000. On May 10, 2012, our Form S-1 registration statement relating to our offer and sale of Renewable Unsecured Subordinated Notes (File No. 333-179460) was declared effective by the SEC, and our offering of notes commenced on May 15, 2012. The registration statement on Form S-1 covers up to $50,000,000 in principal amount of 3 and 6 month and 1, 2, 3, 4, 5, and 10 year notes. For the six month periods ended June 30, 2014 and 2013, we incurred $562,700 and $530,528, respectively, of offering-related expenses, including marketing and printing expense, legal and accounting fees, filing fees, and trustee fees. These costs and expenses are expensed as incurred. From the effective date of May 10, 2012 through August 13, 2014, we have sold a total of $15,307,818 in principal amount of Notes and repaid $1,361,281, for a net raise to date of $13,946,537, exclusive of offering costs as described above. On May 12, 2014, the Company drew $700,000 under an evergreen, uncommitted line of credit from Royal Bank of Canada (the "RBC Line" and "RBC", respectively). Advances under the RBC Line bear interest at a variable annual interest rate of 1 month LIBOR plus 2.25% set at the time of advance for a 30 day term, mature at various dates, and are collateralized by assets held in the Company's marketable securities account. RBC is not obligated to make any extensions of credit to the Company and availability of funds may be increased or decreased by RBC in its sole and absolute discretion. Prepayment of any outstanding principal under the RBC Line may subject the Company to LIBOR break funding costs. On June 16, 2014, the Company purchased a single family home in Garrison, Minnesota for use as a corporate retreat (the "Garrison Property") for a purchase price of $285,000, paid with $57,000 of cash and the proceeds of a $228,000 note (the "Security State Mortgage") advanced by the Security State Bank of Aitkin ("Security State") and secured by a first mortgage. The loan is payable in 239 equal installments of $1,482.10 due on the 16th of each month beginning on July 16, 2014 and one irregular installment of $1,481.51 due on June 16, 2034 (the "maturity date"). The note bears interest at an annual rate equal to the prime rate as published from time to time by The Wall Street Journal plus 0.75%, subject to a floor of 4.75%. Whenever increases occur in the interest rate, Security State, at its option and with notice to the Company, may: (a) increase the Company's payments to insure the loan will be paid off by the maturity date; (b) increase the Company's payments to cover accruing interest; (c) increase the number of the Company's payments; or (d) continue the payments at the same amount and increase the Company's final payment. The loan may be prepaid in whole or in part at any time without penalty. 57 Effective January 31, 2012, TCP sold certain financial rights, but not governance rights, to 496 new membership units, which we refer to as "redeemable preferred units", to John Hanson for a purchase price of $2,745,000, paid by conversion of certain notes payable to him. Effective July 1, 2012, these preferred units were exchanged for preferred units with identical terms issued by TCPH. From the effective date to the redemption date, we paid Mr. Hanson and his designee a guaranteed distribution of $45,750 per month. Effective June 28, 2013, pursuant to a Membership Unit Purchase Agreement, Timothy Krieger, the CEO of the Company, purchased the 496 redeemable preferred units from Mr. Hanson. Concurrently with the purchase, Mr. Krieger and the Company exchanged the redeemable preferred units for an identical number of new Series A Preferred Units (the "Series A Preferred") and the redeemable preferred units were cancelled. The Series A preferred is not redeemable, callable, or convertible, is non-voting with respect to elections to the Board, is senior to the Company's common equity units with respect to rights in liquidation, and is entitled to distributions out of legally available funds in the amount of $92.25 per unit per month. Non-GAAP Financial Measures The Company's communications may include certain non- GAAP financial measures. A "non-GAAP financial measure" is defined as a numerical measure of a company's financial performance, financial position, or cash flows that excludes, or includes, amounts that are included in, or excluded from, the most directly comparable measure calculated and presented in accordance with GAAP in the company's financial statements. Non-GAAP financial measures utilized by the Company include presentations of liquidity measures and debt-to-equity ratios. The Company's management believes that these non-GAAP financial measures provide useful information to investors and enable investors and analysts to more accurately compare the Company's ongoing financial performance over the periods presented. Critical Accounting Policies and Estimates Revenue Recognition and Commodity Derivative Instruments Revenues in our wholesale trading business are derived from trading financial, physical, and derivative energy contracts while those for our retail segment result from electricity sales to end-use consumers. In our trading activities, contracts with the exchanges on which we trade permit net settlement, including the right to offset cash collateral in the settlement process. Accordingly, we net cash collateral against the derivative position in the accompanying consolidated balance sheets. All realized and unrealized gains and losses on derivative instruments are recorded in revenues. Revenue from the retail sale of electricity is recorded in the period in which customers consume the commodity, net of any applicable sales tax. In our retail business, we are exposed to volatility in the cost of energy acquired for sale to customers, and as a result, in October 2012, we began using derivatives to hedge or reduce this variability, since changes in the price of certain derivatives are expected to be highly effective at offsetting changes in this cost. In addition to cash flow hedges, in the first quarter of 2014 we also used certain other contracts to which hedge accounting was not applied to reduce our exposure to higher electricity costs. The gain on these economic hedges is reported as "wholesale trading revenue." 58 Revenues from real estate developments, if any, are recognized at the time of sale closing if all significant conditions are satisfied, including adequate down payment, reasonable assurance of collectability of any notes received, and completion of other contract requirements. Recognition of all or part of the revenue is deferred if any significant conditions are not satisfied. Costs that relate directly to development projects are capitalized and allocated using the specific identification method. Land acquisition, improvements, and holding costs, including real estate taxes and interest are capitalized while a development is in progress. Interest expense, if any, is capitalized based on specific identification of notes payable issued to finance specific assets under development. Once development on a project has been completed and sales have begun, remaining inventory is recorded at the lower of cost or market. Development costs are charged to cost of sales when the related revenue is recognized or when a development is abandoned. Profits Interest Payments Two of our second-tier subsidiaries (SUM and CEF) have Class B members. Under the terms of such subsidiaries' member control agreements, Class B members have no voting rights, are not required to contribute capital, and have no rights to distributions following termination of employment, but are entitled to a defined share of profits while employed. Since Class B members have no corporate governance rights or risk of capital loss (or gain), they do not own non-controlling equity interests and profits interests payments are recorded as compensation expense during the period earned and are classified as accrued compensation on the balance sheet. For the three and six month periods ended June 30, 2014 and 2013, we recorded $236,777, $633,667, $5,423,412, and $2,108,072, respectively, in salaries and wages and related taxes, representing the allocation of profits to Class B members. The amount of accrued profits interests included in accrued compensation at June 30, 2014 and 2013 was $335,777 and $636,117, respectively. 59 |