MISO 2013-2014 Winter Assessment Report Information Delivery and Market Analysis June 2014 Table of Contents I. Executive Summary.................................................................................................. 3 II. Resource Assessment Analysis ............................................................................... 5 III. Market Demand ........................................................................................................ 6 1. Total Real-Time Energy......................................................................................... 7 2. Load Duration Curve Analysis ............................................................................... 8 IV. Market Supply........................................................................................................... 9 1. Generation Resource Analysis .............................................................................. 9 2. Generation Outages ............................................................................................ 15 V. Market Evaluation and Impacts .............................................................................. 19 1. Price Analysis ...................................................................................................... 19 2. Price Convergence and Comparative Price Analysis12 ........................................ 21 3. Border Price Analysis: MISO vs. PJM prices ....................................................... 25 4. Real-Time Interface Prices at the MISO and PJM Interface ................................ 26 5. Ancillary Services Market Analysis ...................................................................... 27 6. Virtual Transactions ............................................................................................. 30 7. RSG..................................................................................................................... 31 8. FTR ..................................................................................................................... 32 VI. Noteworthy Highlights ............................................................................................. 33 1. Membership: South Region Integration ............................................................... 33 2. Extreme Winter Weather Conditions ..................... Error! Bookmark not defined. 3. Control Center Facilities ...................................................................................... 33 4. South Region ICT Services ................................................................................. 33 5. Value Proposition ................................................................................................ 34 2 I. Executive Summary Market outcomes from previous time periods have not been adjusted for membership changes, unless otherwise noted. Caution should be used when making any comparisons. The report provides an assessment of the MISO markets during the 2014 winter period (December 2013, January 2014, and February 2014). A summary of the 2014 winter season found that MISO markets and reliability operations performed well. On December 19th 2013, MISO successfully integrated the MISO South Region, including parts of Arkansas, Louisiana, Mississippi, and Texas. The South Region integration provides the MISO’s Midwest region easier access to natural gas and nuclear generation in the south region, balancing the generation fuel mix and better positioning MISO for future operation challenges. The winter 2014 season was characterized by historic cold weather throughout much of the MISO footprint. Extreme cold conditions impacted the MISO Region on several occasions, with the coldest temperatures in twenty years experienced in early January. While the conditions presented challenging circumstances, MISO and its members were able to reliably manage the power grid during this period. The extreme cold weather resulted in a new winter peak of 109.3 GW on January 6th. The new peak was over 9% higher than the prior winter peak for MISO’s current membership. Even though load obligation dropped by 3.8GW on January 7th, MISO experienced tighter supply conditions due to decreased wind generation, less available generation and reduced imports. MISO curtailed non‐firm exports to non‐deficient entities after declaring a Maximum Generation Emergency Alert and Warning on the morning of January 7th. Overall, temperatures in the MISO footprint during the 2014 winter season were well below normal. Average hourly Real-Time load exceeded 100GW for 56 hours and the hourly average load for winter 2014 was 8.1% higher than that of winter 2013 with membership adjustment. The MISO region continued to rely on coal-fired generating resources for the majority of the time. However, impacted by the MISO South integration, coal’s share of total energy generation declined to 63.2% this winter from 72.6% recorded last winter. The new MISO South region has relatively less coal-fired generation resources and more natural gas resources. The average registered wind capacity for this winter was 13.2 GW, an increase of 6.2% from last winter. The average hourly wind output was 5,083 MW in the 2014 winter season. 3 • In general, wind resources performed as expected during the cold weather conditions. Wind output at MISO’s peak load hours did vary significantly, but those changes were forecasted in advance, allowing MISO to prepare accordingly. • During the extreme cold period in early January, wind generation at the time of peak fell from approximately 6,600 MW on January 6th to 2,300 MW on January 7th. Although icing and cut-outs impacted wind units, MISO effectively managed the losses in the same manner as outages on other units were managed. • Wind generation in January 2014 was 4,467 GWh and set a new monthly record. MISO’s market functions performed as expected during the cold weather conditions. The harsh winter weather put significant upward pressure on market outcomes. • Real-Time average energy and ancillary service market prices for winter 2014 increased substantially when compared with winter 2013, driven by high load conditions and elevated gas prices. • The 3-month average Real-Time LMP for the winter 2014 was $46.88/MWh, which increased 67.6% when compared with winter 2013. • The Real-Time reserve prices in winter 2014 were much higher when compared with winter 2013. High load conditions and Operating Reserve scarcity were the primary drivers for the price increase. • Twenty 5-minute intervals of operating reserve scarcity occurred on January 7th, 2014, and another twelve occurred on February 11th, 2014. o On January 7th, fifteen consecutive Operating Reserve scarcity intervals were experienced during morning ramp period due to the high load conditions and the forced generation outages. o On February 11th, Operating Reserve scarcity was driven by high demand coupled with forced generation outages, including gas supply issues experienced by some natural gas-fired power plants. • The absolute average energy price difference between Day-ahead and Real-Time was $16.84/MWh in the winter 2014, impacted by volatile RealTime energy price. It was $5.50/MWh in the winter 2013. • The combined total of Day-Ahead and Real-Time RSG in winter 2014 was at the highest level in the recent four winter seasons. o Total RSG payment in February 2014 was the highest among winter months since the Ancillary Services Market was launched. 60% of Real-Time RSG in February 2014 was associated with constraint mitigation, a significant portion of which was for congestion management around the Michigan area. Day-Ahead RSG associated with VLR commitments in February 2014 was 63.6% of the total DayAhead RSG. Over 90.0% of the Day-Ahead RSG associated with VLR was for the South Region. 4 II. Resource Assessment Analysis Table 1: Demand and Capacity Analysis for Monthly Peak Demand hours: Winter 2014. 2013 2014 Dec 30 , HE 19 Jan 6 , HE 19 Feb 7th, HE 19 Instantaneous Peak Load 92,082 109,336 103,070 Reserve Requirement 2,410 1,670 2,410 Peak Load Obligation 94,492 111,006 105,480 Capacity Real-Time Emergency Offer* (-) Outages (-) Offer reduction& Wind Derates (+) Net Imports (+) Non-LMR BTMG (-) Online Stranded (-) Emergency Ranges Real-Time Accessible Capacity Capacity Margin (%)** 142,136 19,342 18,458 2,804 636 2,656 1,931 103,188 9.2% 154,990 23,031 14,609 2,695 1,857 3,754 2,381 115,767 4.3% 155,239 29,280 12,172 3,051 1,571 5,283 1,549 111,577 5.8% Load th 2014 th *Emergency offer minus long leadtime resources **Capacity Margin = (Real-Time Accessible Capacity minus Peak Load Obligation)/Peak Load Obligation Table 1 shows the operational analysis of demand and capacity during the monthly peak demand hours of the three months comprising winter 2014. Per MISO procedure, Demand Response resources would not be used unless an Energy Emergency situation was declared. Since no energy emergency occurred in those peak hours, Demand Response Resources were not included in the Capacity margin calculation. MISO did not experience any major reliability issues during the winter of 2014. MISO had 115,767 MW of available capacity to manage this winter’s instantaneous peak demand of 109,336 MW. Based on available capacity, the capacity margin at the winter peak load hour on January 6th was 4.3%. Maximum Emergency Generation Alerts/Warning were issued the operating day January 7th after MISO’s winter peak, due to decreased wind generation, less available generation and reduced imports. The peak load hour in December saw the lowest wind generation for this winter, as shown in Table 2b, Section 4. As a result, generation reductions for Intermittent Resources were highest in that month, relative to the other monthly peak load hours this winter. 5 III. Market Demand Figure 1, Figure 2 and Figure 3, in this section, show the total cleared Real-Time energy for December through February for the years 2011 through 2014, the average hourly load by region for the 2013 and the 2014 winter seasons, and the Load Duration Curves for the 2014 and the two previous winter seasons respectively. Relative to the previous winter seasons, load in the MISO market increased substantially in the 2014 winter season. The increase was driven primarily by membership changes and by extreme winter weather conditions. Membership Change: MISO successfully transitioned part of the electric grid of a four-state region across the south (now called MISO South region) into MISO’s existing market footprint on December 19th, 2013. The integration added several transmission owning members into the MISO market footprint. Demand in the South region made up approximately 20.0%1 of the winter 2014 total Real-Time market energy; accounting for the major portion of the significant increase in Real-Time energy (Figure 1) between the 2014 winter season and the previous winter seasons. Severe Weather Conditions: Overall, temperatures in the MISO footprint during the 2014 winter season were well below normal. During the period of January 5th to January 8th, a polar vortex moved through the MISO footprint. Temperatures in many areas were the coldest experienced in 20 years. Periods of extremely low temperatures were also experienced between January 26th and January 28th, on February 11th, and between March 3th and March 4th. Driven by the extreme low temperatures, a new all-time winter peak load of 109.3GW was set on January 6th, surpassing the previous all-time winter peak for MISO’s current membership by over 9%. Average hourly Real-Time load exceeded 100GW in 56 hours (Figure 2) and daily instantaneous peak load exceeded 100GW on 13 days in January and February 2014. For the current MISO membership, the hourly average load for winter 2014 was approximately 8.1% higher than winter 2013. 1 South region’s Real-Time market demand from December 19th, 2013 to February 28th, 2014 as a percentage of MISO’s Real-Time market demand from December 1st, 2013 to February 28th, 2014. 6 1. Total Real-Time Energy Figure 1: Total Real-Time Energy for the Winter Months of 2011, 2012, 2013 and 2014. 2011 180 2012 2013 2014 160 140 TWh 120 100 80 60 40 20 0 Dec Jan Feb Winter-12 Winter-13 Winter-14 Load has not been adjusted for membership changes. Figure 2: Average Real-Time Hourly Load by Region for Winter 2013 and Winter 2014. MW CENTRAL NORTH SOUTH 50 45 40 35 30 25 20 15 10 5 0 Dec Jan Winter 2013 Feb Dec Jan Feb Winter 2014 South region average load for December 2013 includes data from December 1st, 2013 to December 31st, 2013. 7 2. Load Duration Curve Analysis The seasonal load duration curve indicates the number of hours during the winter season when Real-Time Load was greater than a given level within the MISO footprint. GW Figure 3: MISO Load Duration Curves** for Winter 2012, Winter 2013, and Winter 2014. 115 110 Hours w ith Load >100GW Hours w ith Load >80GW Hours w ith Load >70GW Hours w ith Load >60GW Hours w ith Load >55GW 105 Winter 2014 56(2.6%) 1020(47.2%) 1619(75.0%) 2017(93.4%) 2097(97.1%) 100 Winter 2013 0(0.0%) 0(0.0%) 39(1.8%) 976(45.2%) 1515(70.1%) 95 Winter 2012 0(0.0%) 0(0.0%) 46(2.1%) 995(45.6%) 1519(69.6%) 90 85 80 75 70 65 60 55 50 45 40 35 30 1 219 437 655 873 1091 1309 1527 1745 1963 2181 Number of Hours Load has not been adjusted for membership changes. MISO South Region was integrated into the MISO market footprint on December 19th, 2013. December 2011 (part of winter 2012) load includes Duke Energy Ohio load, which was successfully transitioned into PJM on January 1st, 2012. 8 Market Supply 1. Generation Resource Analysis Winter-12 Winter-13 Winter-14 63.2% 70% 72.6% 80% 68.2% Figure 4: Total Generation by Fuel Type2 for the Winters of 2012, 2013, and 2014. 60% 50% 2.6% 1.1% 1.5% 13.9% 13.2% 14.4% 7.0% 8.5% 10% 7.5% 8.4% 20% 4.6% 30% 13.3% 40% 0% Coal Gas Wind Nuclear Other Note: Other is comprised of Hydro, Oil, Other, Pet Coke, and Waste. Figure 5: Total Generation by Fuel Type by Region for Winter 2014. Central Region 5.3% 24.4% 1.4% 10% 0.5% 7.9% 20% 11.1% 30% 3.8% 40% 23.4% 29.1% 50% 11.1% 41.2% 60% 0.0% 70% 2.5% 80% South Region 60.3% 90% North Region 78.1% IV. 0% Coal Gas Wind Nuclear Other The MISO region continued to rely on coal-fired generating resources the majority of the time. However, impacted by the generation diversity in the South Region 2 Based on 5-minute unit level generation dispatch target 9 – relatively less coal-fired generation resources and more natural gas resources – coal’s share of total energy generation declined to 63.2% this winter. In the winter of 2012, due to historically low gas prices and increased wind generation, coal units accounted for 68.2% of the total energy produced, which was lower than the percentages noted in winter 2013. Natural Gas resources usually are more expensive than other resources and are generally dispatched at a low capacity factor. In winter 2012, natural gas units accounted for 8.4% of total MISO generation due to the historically low gas prices. However, this winter, gas’s share of total generation was even higher than that of 2012 due to the gas-fired generation’s contribution in the South region. Nuclear units are among the lowest-cost resources and therefore, normally operate at higher capacity factors. Their percent of the total generation for winter 2014 remained about the same when compared with the winters of 2012 and 2013. Figure 5 shows the total regional generation by fuel type for winter 2014. Benefiting from the generation diversity in the South region, less coal and more gas generation, MISO reduced the dependence on coal and increased the portion of gas generation. Lower percentage of coal generation in the South Region had a downward influence on the total coal contribution in MISO. While higher percentage of gas generation in the South Region contributed to the increase of gas share of total energy generation. The interest in renewable energy gained momentum to combat environmental concerns about the effects of fossil fuel combustion. On June 1st, 2011, MISO successfully launched Dispatchable Intermittent Resources (DIRs), allowing registered intermittent resources to participate in the Real-Time energy market. As of Dec 1st, 2014, the registering Dispatchable Intermittent Resources (DIRs), MISO had a total of 10,535 MW of registered DIR capacity. Table 2a: Percent of Wind Generation at MISO for Winters 2012, 2013 and 2014. Wind Energy as a Percentage of MISO Energy3 DIR Energy as a Percent of Total Wind Energy4 Winter 2012 Dec Jan Feb Winter 2013 Dec Jan Feb Winter 2014 Dec Jan Feb 7.1% 8.7% 6.9% 7.4% 9.4% 8.1% 6.1% 6.9% 6.3% 17.2% 17.0% 33.3% 53.7% 53.1% 55.6% 81.5% 79.1% 78.8% The average share of total generation in the MISO region attributed to wind was 6.5% and DIR increased to around 80.0% of the total wind energy in winter 2014. Figure 6: Hourly Average of Real-Time Wind Generation4 during Winters 2012, 2013 and 2014. 3 4 Hourly ICCP Data Source: Historical Hourly Wind Data 10 Average Wind Generation Registered Wind Capacity 13,500 11,500 MW 9,500 7,500 5,500 3,715 4,568 5,203 3,632 3,895 6,032 4,520 4,131 5,087 3,500 1,500 -500 Dec-11 Jan-12 Feb-12 Capacity Factor 34.8% 43.1% 34.3% Dec-12 Jan-13 Feb-13 31.7% 42.4% 36.8% Dec-12 Jan-13 Feb-13 31.7% 46.3% 39.0% The capacity factor for wind energy is limited by its inherent properties and is calculated as the ratio of actual wind generation output to the registered wind capacity. Figure 6 shows that registered wind capacity and average winter wind generation have consistently grown in the MISO market for the last three winters. The average registered capacity for this winter was 13,035MW, an increase of 6.2% from that of last winter. Wind generation output for this winter averaged 5,083 MW, an increase of 12.0% from last winter. Wind generation in January 2014 was 4,467 GWh and set a new monthly record. The instantaneous wind peak this winter was 9,954MW on February 26th, while the all-time wind peak was 10,021 MW set on November 23rd, 2012. Wind output exceeded 9,000 MW for 92 hours this winter, and it was 60 hours in the last winter. The volatility of the wind generation, measured in terms of the standard deviation, has also been consistently increasing for the last three winter seasons, presenting potential challenging operational issues. However, the implementation of Dispatchable Intermittent Resources (DIRs) has resulted in a decrease in MWh of wind curtailments, as well as the duration of curtailments. Table 2b: Wind Generation5 at MISO Monthly Peak Load Hours for Winters 2011, 2012, and 2013. Winter 2012 Winter 2013 Winter 2014 (MW) Dec Jan Feb Dec Jan Feb Dec Jan Feb Peak Load Hour 762 2,243 1,218 6,954 6,839 Wind 2,696 7,562 1,100 2,326 Generation Wind 3.3% 1.0% 3.1% 1.3% 6.4% 6.6% Generation % of 3.6% 10.5% 1.6% Peak Load 11 The table above shows wind generation at the monthly peak load hour for this winter and the previous winters. Wind generation output was 6,954 MW or 6.4% at the hour of the 2014 winter peak load on January 6th, 2014. 110% 94.4% 96.8% 95.8% Figure 7: Average Percentage of time a fuel is at the margin in Real-Time during the winters of 2012, 2013 and 2014. 69.9% 90% 50% 44.8% 48.2% 50.8% 70% Coal Gas^^ Winter 2012 1.2% 2.1% 2.5% -10% 0.1% 0.0% 0.0% 10% 1.4% 1.2% 1.9% 5.9% 5.8% 30% Hydro Nuclear Oil Winter 2013 Wind Winter 2014 Note: Binding transmission constraints can produce instances where more than one unit is marginal in the system. Consequently, more than one fuel may be on the margin; and, since each marginal unit is included in the analysis, the percentage may sum to more than 100%. In addition, on June 1st, 2011, MISO successfully launched Dispatchable Intermittent Resources (DIRs), allowing wind to participate in the RealTime energy market. ^^Gas excludes Combined Cycle units Figure 7 above shows that Coal was the major fuel at the margin, setting RealTime LMPs over 90.0% of the time. This was a substantial increase of gas units setting the price in winter 2014. Impacted by the high gas fired generation in the South Region, more gas units were committed due to the high load conditions, gas as a marginal fuel, increased substantially to 50.8% of the time this winter. Consistent with the increase of wind generation, Dispatchable Intermittent Resources (DIRs) setting the Real-Time price increased to 69.9% of the time in winter 2014. Figure 8: Total Imports and Exports during the Winters of 2012, 2013, and 2014. 12 Winter2012 629 Abs Diff of Hourly Imports 1,366 Stdev of Hourly Imports 6,000 5,000 Winter2013 620 866 Winter2014 896 1,267 GWh 4,000 3,000 2,000 1,000 0 Dec-11 Jan-12 Feb-12 RT Imports Dec-12 Jan-13 Feb-13 RT Exports DA Imports Dec-13 Jan-14 Feb-14 DA Exports Figure 8 shows that similar to previous winters, MISO continued to be a net importer of electricity this winter. However the net imported energy decreased this winter when compared with winter 2012 and winter 2013. During the cold snap in January MISO effectively managed the all-time winter peak and also supported neighboring entities. The table inserted into Figure 8 shows the absolute differences between RealTime and Day-Ahead hourly imports, and the volatility of Real-Time imports, measured by standard deviation for the last three winters. The absolute difference between Real-Time and Day-Ahead imports is important to MISO’s Real-Time operations, as large differences require unit commitment and dispatch changes in the Real-Time market relative to the Day-Ahead market. Compared with winter 2013, the absolute difference and the imports volatility for winter 2014 increased. 13 Figure 9: Average Monthly Generation Fuels Prices: Coal, Natural Gas Spot Prices and Distillate Fuel Oil: Winters 2012, 2013, and 2014 $26.00 Gas Nominal price Powder Basin Coal Nominal price Illinois Basin Coal Nominal price Distillate Fuel Oil Nominal price $25.00 $24.00 $23.00 $22.00 $21.00 $20.00 $19.00 $18.00 $/MMbtu $17.00 $16.00 $15.00 $14.00 $13.00 $12.00 $11.00 $10.00 $9.00 $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb 2012 2013 2014 Note: Source of fuel prices is publicly available government Sources (EIA and ICE). Natural Gas Prices are for Chicago Hub with Price Index = 2000 and Coal prices are for Illinois Basin with Heat Content = 11,800 Btu/lb. Powder River Basic Coal Heat Content =: 8,800 Btu/lb; Distillate Fuel Oil Heat Content: 5.825 mmbtu/barrel. Fuel supply conditions influence regional fuel market spot prices (Figure 9). Such conditions include the proximity of the fuel sources, international export demands for fuels, contractual terms, delivery certainty, transportation, pollution abatement costs and competing end-uses of a fuel. Winter 2014 average Illinois Basin prices remained about the same when compared with last winter season. Month-over-month coal prices have essentially remained flat since early 2012. Powder River Basin coal prices increased 18.7% from winters 2012. Gas prices, which averaged $8.38/MMBtu in January 2014 and $12.04/MMBtu in February 2014, were at the highest level since August 2008. The harsh weather conditions experienced this winter season continued to put a strain on gas supply conditions and cause high demand for gas in winter 2014. Natural Gas averaged $2.92/MMbtu in winter 2012, $3.46/MMbtu in winter 2013 and $8.33/MMbtu in winter 2014. Average natural gas price for winter 2014 more than doubled when compared to winter 2013. Through February 2013, the April 2012 gas price of $2.05/MMbtu was the lowest since the start of MISO energy markets. The highest price observed since April 2005 was $12.96/MMbtu observed in December 2005. 14 Distillate fuel oil markets in the United States involve two products: low-sulfur distillate, which is used as a transportation fuel (diesel) for on-highway vehicles, and high-sulfur distillate, which is used for space heating (heating oil) in the residential and commercial sectors and as a fuel for other stationary (nontransportation) applications in the commercial, industrial, and electricity generation sectors. The market’s present need for oil is reflected in the current price. Prices in distillate fuel oil markets respond quickly to changes in supply and demand. Average monthly prices for Distillate Fuel Oil are somewhat volatile. The Distillate Fuel Oil price in winter 2014 was $23.34/MMbtu, a decrease of 3.2% from winter 2013. . Oil was marginal 2.5% of the time in winter 2014 which increased when compared with that with the past two winters, reflective of the colder overall temperatures this winter. 2. Generation Outages Figure 10 shows the generator outages that occurred in each month for the winters of 2012, 2013, and 2014. Generator Operators are responsible for submitting generator outages, including derates to MISO. MISO evaluates the impact on transmission system reliability and helps coordinate the rescheduling of planned outages and the development of mitigation procedures, when required, to maintain transmission system reliability. Figure 10: Monthly Avg. of Generation Outages by Types during the Winters of 2012, 2013, and 2014. 20,000 Forced Planned 18,000 16,000 14,000 MW 12,000 10,000 8,000 6,000 4,000 2,000 0 Dec-11 Jan-12 Feb-12 Winter-12 Dec-12 Jan-13 Feb-13 Winter-13 Dec-13 Jan-14 Feb-14 Winter-14 Note: Generation outages are point in time data and were extracted in the respective reporting months. Values may change if extracted again. Derates are not included. Data includes both MISO market and reliability footprints. Please note that in Winter 2014 Early January experienced the coldest temperatures in two decades. The extreme weather conditions affected supply contributing to 15 operational challenges. The average forced generation outages in winter 2014 increased 16.1% when compared with winter 2013. The forced generation outages during the cold snap period resulted in very tight supply conditions and contributed to high energy prices, heavy congestions and high RSG payments. As the severe weather conditions moved into the footprint at the beginning of January, freezing components and fuel restrictions caused challenges for many units. Figure 11: Daily Average Forced and Planned Outages for Early January th Total Forced Generation outage prior to January 4 includes the forced outages due to mechanical failure and gas issues. The Figure 11 above indicates that the increasing forced generation outages during the polar vortex period. The forced generation outages were broken down in two groups – forced outages due to gas issues and forced outages due to mechanical failures. • During polar vortex period (Jan 6th-Jan 8th), natural gas restrictions were a major impact factor on the gas-fired units which could not procure natural gas during the cold weather. While planned outages had minor impacts during this cold weather event, • Increased forced generation outages on January 7th diminished the capacity situations and caused MISO to issue the Maximum Emergency Generation Alert/Warning on that day. Figure 12: Daily Forced Outage Comparison Breakdown by Fuel Type 16 The figure 12 above provides a historical comparison of forced outages by fuel type. This data includes only the area that is now MISO’s North and Central Regions to provide accurate year‐over‐year comparisons since MISO’s South Region was integrated into MISO footprint on December 19, 2013. • The total forced outages from gas-fired and oil-fired units increased significantly due to fuel procurement issues or mechanical failure during the polar vortex period. • The outage from coal units decreased notably as coal units are generally base loaded and are needed to be online to meet high load obligation during the Jan 6-8, 2014. Figure 13: Daily Energy and ASM Products Pricing 17 • • High Real-Time price on Jan 7th mostly due to operating reserve scarcity in He 8. Hourly integrated price spiked over $1,600/MWh for that hour. On Jan 7th, operating reserve scarcity intervals were noted from 7:05 to 8:15 in the morning, resulting hourly SMP spiked over $1,600/MWh at the hour ending 8. The forced generation outage, steep load growth were the main drivers for operating reserve scarcity. Figure 13: Daily LMP by hubs and Natural Gas prices by Hubs $/MWh Daily LMPs by Hubs ILL_RT IND_RT MICH_RT MINN_RT ARK_RT LOU_RT TEX_RT 300 250 200 150 100 50 0 1/6/2014 $/MMBTU Chicago City $13.19 • • 1/7/2014 Henry Hub $4.30 Chicago City $7.40 1/8/2014 Henry Hub $4.50 Chicago City $5.40 Henry Hub $4.50 Impacted by congestion between the North/Central Regions of the footprint and the South Region, the Real-Time LMPs at the South Hubs were much higher when compared with LMPs at Midwest hubs on January 6th. On January 7th, due to the gas supply issues in Midwest, the Real-Time LMPs at Midwest hubs were higher than the prices at the South Region hubs. 18 V. Market Evaluation and Impacts 1. Price Analysis5 The market price is a manifestation of the prevailing demand and supply conditions. The price trend and its volatility are basic measures of market behaviors and performance for a given period. The following section indicates that the MISO market outcomes were as expected for a competitive market. For the 2014 winter season, the majority of the footprint experienced coldest temperatures in two decades. Severe weather events were declared a couple of times and a Maximum Generation Warning was called on January 7th. The harsh winter weather put significant upward pressure on the market outcomes. In contrast, the average temperatures of winter 2013 were above the normal and winter 2012 was one of the warmest winters in recorded history. Table 3: MISO Hourly Avg. of RT LMP and DA LMP for 3-months of Winter 2012, 2013, and 2014. 2012 2013 2014 Day Real Day Real Day Real LMP ($/MWh) Ahead Time Ahead Time Ahead Time Dec $29.98 $27.91 $28.59 $28.02 35.66 34.01 Jan $26.10 $24.93 $28.87 $28.46 51.64 49.16 Feb $25.57 $25.04 $27.68 $27.42 56.42 57.48 3-Mth Avg. $27.22 $25.96 $28.38 $27.97 $47.91 $46.88 Day-Ahead and Real-Time average energy market prices for winter 2014 increased substantially when compared with winter 2012 and 2013, driven by high load conditions and gas prices due to the extremely cold weather. The 3-month average Day-Ahead LMP for winter 2014 was $47.91/MWh, which was 68.8% and 76.0% higher than the 3-month average of winter 2013 and 2012, respectively. The 3-month average Real-Time LMP for the winter 2014 was $46.88/MWh, which increased 67.6% and 80.0% respectively when compared with winter 2013 and winter 2012. Daily average Real-Time LMPs exceed $50.00/MWh for twenty-eight days in winter 2014. The system-wide hourly average Real-Time price exceeded $100.00/MWh for one hundred and eight hours this winter, mainly due to reserve shortages and congestions. The highest system-wide Real-Time hourly LMP for the winter 2014 was $1780.7/MWh, incurred on January 7th, 2014, in HE 8. Consecutive Operating reserve scarcity intervals were noted in that hour. The daily system-wide Real-Time LMP exceeded $180.0/MWh for that day, mainly reflective of the tight operating conditions. Max Gen Alerts/Warning were declared on that day. Figure 13: MISO Hourly Avg. of RT LMP and RT Load for Winters of 2012, 2013, and 2014. 5 MISO system-wide prices are based on the hourly average of the hubs. 19 200 120,000 180 100,000 160 80,000 120 MW $/MWh 140 100 60,000 80 40,000 60 40 20,000 20 0 12/1 12/4 12/7 12/10 12/13 12/16 12/19 12/22 12/25 12/28 12/31 1/3 1/6 1/9 1/12 1/15 1/18 1/21 1/24 1/27 1/30 2/2 2/5 2/8 2/11 2/14 2/17 2/20 2/23 2/26 2/29 0 Month RTLMP 12 RTLMP 13 RT LMP 14 RT Load 12 RT Load 13 RT Load 14 Dec $27.91 $28.02 $34.01 60,235 56,830 84,957 Jan $24.93 $28.46 $49.16 58,735 60,038 82,475 Feb $25.04 $27.42 $57.48 57,311 59,437 68,449 3-Mth Avg. $25.96 $27.97 $46.88 58,760 58,768 78,499 The MISO footprint experienced extremely cold weather and recorded 10 days of daily peak loads over 100 GW in January. A new all-time winter peak load of 109.3GW was set on January 6th, surpassing the previous all-time winter peak (membership adjusted) of 99.6GW in 2010. The maximum instantaneous peak load for winter 2013 was 74,430 MW on January 22nd.. On December 19th 2013, the MISO South Region was successfully integrated into MISO’s market operations. 20 Price Convergence and Comparative Price Analysis12 2. Figure 14: DA and RT Hourly LMP Convergence for MISO: Winters of 2012, 2013, and 2014. Avg. DALMP 82 Avg. RTLMP Avg. Difference (DA-RT) 24.85 18.79 5.79 5.87 4.79 7.06 Dec - 13 5.76 4.45 3.36 Jan - 13 22 12 27.26 25.98 28.40 27.99 32 28.59 28.02 28.87 28.46 27.68 27.42 42 29.98 27.91 26.10 24.93 25.57 25.04 $/MWh 52 35.66 34.01 62 47.62 46.53 51.64 49.16 56.42 57.48 72 Absolute Avg. Diff. 16.84 4.55 5.50 2 Winter-14 Winter-13 Winter-12 Feb - 14 Jan - 14 Feb - 13 Dec - 12 Feb - 12 Jan - 12 Dec - 11 -8 Figure 16 above shows that the hourly averages of both Day-Ahead and RealTime prices for the past three winters. In general, the market has tended to exhibit slight Day-Ahead price premiums. While Real-Time price premium is mainly impacted by the Operating Reserve Scarcity in Real-Time. Drive by the exemlely cold weather, the hourly averages of both Day-Ahead and Real-Time prices during the 2014 winter were much higher than winter 2012 and 2013, and were the highest since the Ancillary Service market was started in 2009 as well. The absolute average price difference increased to $16.84/MWh in the 2014 winter from $5.50/MWh in the 2013 winter, indicating that the price difference almost trippled. Real-Time price was more volatile this winter, due to the tight operation conditions. The average MISO system-wide price difference between the Day-Ahead and Real-Time markets increased to $1.09/MWh this winter from $0.41/MWh last winter. 21 Figure 15: Scatter Plot of Average Daily DA and RT LMP Differences: Winter 2012. 40 CIN IND ILL MICH MINN DA LMP minus RT LMP ( $/MWh) 95% quantile of MISO price difference for Dec 2011 - Feb 2012 20 0 -20 5% quantile of MISO price difference for Dec 2011- Feb 2012 CIN IND ILL MICH MINN Mean $0.35 $0.92 $2.30 $1.04 $1.03 StdDev $3.93 $3.55 $5.50 $3.73 $4.49 95% Quantile $5.70 $5.73 $13.09 $6.37 $9.14 5% Quantile -$4.88 -$6.05 -$4.61 -$5.39 -$6.54 29-Feb-12 24-Feb-12 19-Feb-12 14-Feb-12 09-Feb-12 04-Feb-12 30-Jan-12 25-Jan-12 20-Jan-12 15-Jan-12 10-Jan-12 05-Jan-12 31-Dec-11 26-Dec-11 21-Dec-11 16-Dec-11 11-Dec-11 06-Dec-11 01-Dec-11 -40 Figure 16: Scatter Plot of Average Daily DA and RT LMP Differences: Winter 2013. 80 IND ILL MICH MINN 95% quantile of MISO price difference for Dec 2012- Feb 2013 40 20 0 -20 -40 $6.29 $4.46 $6.97 $5.05 $10.89 $5.85 $9.88 5% Quantile -$8.57 -$5.60 -$13.79 -$5.81 01-Mar-13 $4.03 95% Quantile 24-Feb-13 StdDev 19-Feb-13 $0.54 14-Feb-13 MINN $0.36 09-Feb-13 MICH $0.63 04-Feb-13 ILL $0.14 30-Jan-13 20-Jan-13 15-Jan-13 10-Jan-13 05-Jan-13 31-Dec-12 26-Dec-12 21-Dec-12 16-Dec-12 11-Dec-12 -80 06-Dec-12 5% quantile of MISO price difference for Dec 2012- Feb 2013 IND Mean 25-Jan-13 -60 01-Dec-12 DA LMP minus RT LMP ( $/MWh) 60 22 Figure 17: Scatter Plot of Average Daily DA and RT LMP Differences: Winter 2014. 170 IND DA LMP minus RT LMP ( $/MWh) 120 ILL MICH MINN ARK LOU 95% quantile of MISO price difference for Dec 2013- Feb 2014 70 20 -30 -80 -130 5% quantile of MISO price difference for Dec 2013- Feb 2014 IND ILL MICH MINN ARK LOU Mean $5.10 $4.73 $7.84 $1.56 -$4.63 -$0.50 StdDev $39.65 $29.29 $40.29 $23.36 $21.80 $22.49 95% Quantile -$19.20 -$28.12 -$31.53 -$22.82 -$42.74 -$41.99 5% Quantile $29.87 $25.35 $52.56 $21.95 $15.60 $21.79 01-Mar-14 24-Feb-14 19-Feb-14 14-Feb-14 09-Feb-14 04-Feb-14 30-Jan-14 25-Jan-14 20-Jan-14 15-Jan-14 10-Jan-14 05-Jan-14 31-Dec-13 26-Dec-13 21-Dec-13 16-Dec-13 11-Dec-13 06-Dec-13 01-Dec-13 -180 The scatter diagrams in Figures 15, 16 and 17 above, based on statistical analysis, show daily average hourly price differences between the Day-Ahead and RealTime markets at the MISO Hubs during the 2012, 2013, and 2014 winters, respectively. The table inserted within the scatter diagrams contains additional statistics calculated from DA-RT LMP differences based on data over the three winter months of each year. The estimated measures of price dispersion reflect price volatility due to demand-supply interactions that occurred to clear the respective markets. Price differences between Day-Ahead and Real-Time markets exist due to market uncertainties inherent in a competitive bidding process, expectations of participants, transmission constraint management practices, and the way RAC and Real-Time resource commitment processes are implemented. Most of the observations clustered around the zero line show a general convergence pattern. The data points outside the statistical reference bands indicate relative price divergence between the Day-Ahead and Real-Time markets at the respective hubs. Congestions and scarcity were the major contributors to price volatility. Winter 2014brought coldest temperatures in two decades and extreme conditions affected supply contributing to operational challenges. Extremely weather resulted in record levels of energy prices and price volatilities. DA/RT price convergence was poor during peak and off-peak periods this winter. 23 On January 6th and 7th, Operating Reserve scarcity was experienced which caused sharp Real-Time price spikes and resulted in significant Real-Time premiums for all the hubs. On January 7th, in HE 8, the system-wide hourly Real-Time LMP exceeded $1700.00/MWh due to the consecutive Operating Reserve scarcity intervals in that hour. On January 27th and 28th, Day-Ahead prices were over $300/MWh across the North and Central Regions due to the transmission constraints, which resulted in large Day-Ahead price premiums for the Indiana and Minnesota Hubs. The Operating Reserve scarcity on February 11th caused sharp Real-Time price spikes and resulted in significant Real-Time premiums for all the hubs. Twelve Operating Reserve scarcity intervals, in total, were noted on that day. Impacted by congestion between the North/Central Regions of the footprint and the South Region, the Real-Time LMPs at the South Hubs were much higher when compared with Day-Ahead LMPs for several days in February The Michigan Hub, in particular, was impacted by heavy congestion around the Michigan area. The Hub experienced hourly LMPs that exceeded $100.00/MWh for total 242 hours in the Day-Ahead market. Congestion around the Michigan area contributed to the high Day-Ahead premiums in January and February. Figure 18: Monthly Hourly Average Price Comparison across MISO and Neighboring Markets: Winter 2012, 2013, and 2014. $180 Winter - 12 Winter - 13 $160 Winter - 14 139 $140 138 $/MWh $120 $100 77 $80 $60 $40 48 27 28 32 34 84 75 31 39 36 73 47 26 28 32 33 78 71 29 39 34 $20 $MISO PJM NYISO ISO-NE Day - Ahead Market MISO PJM NYISO ISO-NE Real-Time Market Figure 18 shows the hourly average prices in the Day-Ahead and Real-Time markets for MISO6 and neighboring RTO markets during the winters of 2012, 2013, and 2014. Relative to the previous two winters, winter 2014 average LMPs across all the 6 MISO system-wide prices are based on the hourly average of the hubs. 24 ISOs increased in both the Day-Ahead and Real-Time markets, consistent with the increased weather sensitive load and gas supply stress this winter. When compared with the neighboring RTO markets, the average energy prices in MISO were relatively low. MISO experienced winter peak conditions on January 6th. Reduced peak load obligations on subsequent days freed up resources allowing MISO to assist PJM as the extreme cold temperatures moved into the East. General grid resiliency and flexibility allowed MISO to assist neighbors during these events. 3. Border Price Analysis: MISO vs. PJM prices In order to evaluate price convergence between the two adjacent RTO markets, MISO performed a comparative evaluation of prices at the individual MISO and PJM border buses. The buses chosen for the analysis are electrically close (or identical) and representatively spread across the PJM/MISO border. The LMPs used in the analysis are hourly integrated values. Table 4: Average price at the MISO and PJM border buses during the 2012 winter. Buses P Dec-11 MISO PJM Jan-12 MISO P P Feb-12 MISO PJM P $5.27 $22.08 $24.72 $6.97 $21.72 $25.23 $5.08 $25.63 $27.64 $6.88 $27.16 $29.36 PJM Kincaid (PJM) Vs Coffen (MISO) $8.24 $21.53 $24.51 $7.29 $21.57 $26.41 Cook (PJM) vs Palisades ( MISO) $6.81 $28.61 $31.31 $8.63 $27.13 $29.02 P is the absolute price difference between PJM and MISO. Winter - 12 MISO PJM Table 5: Average price at the MISO and PJM border buses during the 2013 winter. Buses Kincaid (PJM) Vs Coffen (MISO) Cook (PJM) vs Palisades ( MISO) P Dec-12 MISO PJM P Jan-13 MISO PJM P Feb-13 MISO PJM P Winter - 13 MISO PJM $7.80 $22.00 $21.78 $8.37 $25.18 $27.01 $7.65 $23.78 $26.04 $7.95 $23.65 $24.91 $6.69 $27.53 $27.87 $8.26 $27.56 $30.87 $8.82 $28.89 $32.47 $7.89 $27.96 $30.33 P is the absolute price difference between PJM and MISO. Table 6: Average price at the MISO and PJM border buses during the 2014 winter. Buses Kincaid (PJM) Vs Coffen (MISO) Cook (PJM) vs Palisades ( MISO) P Dec-13 MISO PJM P Jan-14 MISO PJM P Feb-14 MISO PJM P Winter - 14 MISO PJM $7.26 $27.55 $30.07 $34.43 $37.69 $58.75 $23.19 $43.95 $47.93 $21.58 $36.14 $45.50 $6.68 $30.86 $32.09 $36.38 $52.47 $69.01 $58.05 $91.00 $51.00 $32.90 $57.01 $50.69 P is the absolute price difference between PJM and MISO. Tables 4, 5 and 6 above show price comparisons at the PJM and MISO border buses between the 2012, 2013, and 2014 winter seasons. The absolute price differences in winter 2014 were much wider than winters of 2012 and 2013 at all the border buses. 25 4. Real-Time Interface Prices at the MISO and PJM Interface MISO continuously imports energy from, and exports to, external regions. This section analyzes the Real-Time interchange transactions between MISO and PJM. These transactions may fulfill long-term or short-term bilateral contracts, or take advantage of short-term price differentials. MISO’s imports from PJM and MISO’s exports to PJM are scheduled in the MISO market at a single interface node -- MISO’s PJM Interface. Similarly, PJM’s imports from MISO and its exports to MISO are scheduled in PJM’s market at a single interface node -- PJM’s MISO Interface. MISO estimated (i) LMPs at both the MISO and PJM Interfaces; (ii) the Economic Inefficiency; and (iii) the Revenue7 for the winters of 2012, 2013 and 2014. Table 7 below shows summary statistics for the Real-Time hourly LMPs at MISO’s PJM Interface and PJM’s MISO Interface. During the winter 2014, the hourly average of MISO LMP at its MISO Interface was $46.85/MWh, while the PJM LMP at its PJM Interface was $47.14/MWh; a difference of -$0.27/MWh. While in the winter of 2013, the hourly average of the MISO LMP was higher than the hourly average of PJM LMP by a difference of $0.78/MWh. Table 7: Real-Time Hourly Interface Prices for the Winters of 2012, 2013 and 2014. Interface LMP Average Winter 2012 MISO LMP at its PJM Interface PJM LMP at its MISO Interface Interface Price Difference (MISO – PJM ) Absolute Interface Price Difference (MISO – PJM ) Winter 2013 $ 26.76 $27.80 $ 25.65 $27.02 $ 1.12 $0.78 $6.15 $6.40 Standard Deviation Winter 2014 $46.85 $47.14 -$0.27 $21.52 Winter 2012 Winter 2013 $ 10.93 $12.27 $ 9.04 $11.05 $11.88 $15.21 $10.23 $13.81 Winter 2014 $59.38 $90.26 $77.78 $74.74 During winter 2014, the standard deviation of the PJM Real-Time hourly price at its MISO Interface was $90.26/MWh, while the standard deviation of MISO LMP at its PJM Interface was $59.38/MWh. This indicates that the volatility of the MISO LMP at its PJM Interface was less than the volatility of the PJM LMP at its MISO Interface. 7 Revenue is interface price difference (MISO’s PJM Interface price minus PJM’s MISO Interface price) multiplied by the net MWh flow from PJM to MISO 26 Table 8: Economic Inefficiency and Revenue for Winters 2012, 2013 and 2014. Winter 2012 % of hours when flow is not consistent with the interface price 51% differences (MISO – PJM ) Economic Inefficiency (in millions) $9.69 Overall Revenue from Real-Time Scheduling (in millions) $5.51 Winter 2013 Winter 2014 47% 50% $3.66 $4.06 $27.05 $19.70 An economic inefficiency occurs when the direction of energy flows is not consistent with price differentials. The economic inefficiency for a particular hour was defined as economic losses when aggregate flow was from the RTO with a high interface price to the RTO with a low interface price. This was estimated as the negative of the minimum of zero and the interface price difference multiplied by the MWh of flow. The direction of energy flows was consistent with price differentials in 50% of hours for winter 2014. The estimated value of Economic Inefficiency for the winter 2014 was $27 million, as shown in the above table. As indicated in Table 8 above, despite economically inefficient transactions for a part of the winter period, it must be noted that MPs may collectively make money by engaging in Real-Time scheduling at the PJM and MISO interfaces. In winter 2014, out of 2,160 hours, market participants earned revenues of $46.74 million in 1,070 hours and incurred losses of $27.05 million in 1,090 hours, yielding overall revenues of $19.70 million. This was a significant increase from the overall Real-Time scheduling revenues earned in winter 2013 of $4.06 million, mainly attributed to the increased overall interface price divergence and rising interchange quantities between PJM and MISO. 5. Ancillary Services Market Analysis On December 17th, 2012, MISO began Frequency Regulation Compensation (FERC Order 755) in order to compensate frequency regulating resources on the actual regulation service provided. On December 19th, 2013, the MISO South Region was successfully integrated into MISO’s market operations. 27 Figure 19: MISO Wide Daily Day-Ahead and Real-Time MCPs: Winters 2012, 2013, and 2014. REG_RT_MCP REG_DA_MCP RT_REGMILEAGE SPIN_DA_MCP SUPP_RT_MCP SUPP_DA_MCP $100 Winter-2012 $90 Winter-2013 SPIN_RT_MCP Winter-2014 $80 $/MWh $70 $60 $50 $40 $30 $20 $10 12/1/2011 12/7/2011 12/13/2011 12/19/2011 12/25/2011 12/31/2011 1/6/2012 1/12/2012 1/18/2012 1/24/2012 1/30/2012 2/5/2012 2/11/2012 2/17/2012 2/23/2012 2/29/2012 12/6/2012 12/12/2012 12/18/2012 12/24/2012 12/30/2012 1/5/2013 1/11/2013 1/17/2013 1/23/2013 1/29/2013 2/4/2013 2/10/2013 2/16/2013 2/22/2013 2/28/2013 12/6/2013 12/12/2013 12/18/2013 12/24/2013 12/30/2013 1/5/2014 1/11/2014 1/17/2014 1/23/2014 1/29/2014 2/4/2014 2/10/2014 2/16/2014 2/22/2014 2/28/2014 $0 Figure 19 above shows the daily average price trends of the Ancillary Service Product (AS) clearing prices during the previous three winters. The marginal clearing prices in winter 2014 were much higher when compared with winter 2012 and winter 2013. High load conditions and Operating Reserve scarcity were the primary drivers for the price increase. In addition, gas supply related generation outage issues put significant upward pressure to the ancillary service market. On January 7th, fifteen consecutive Operating Reserve scarcity intervals were experienced during morning ramp period due to the high load conditions and the forced generation outages. The daily average of Ancillary Service product prices exceeded $100.00/MWh. On February 11th, twelve Operating Reserve scarcity intervals occurred, causing a very high daily average of Ancillary Service product prices. Table 9 below shows the percent change in ancillary service prices from winter 2014 against winters 2012 and 2013. Table 9: MISO Wide Ancillary Service Price Comparison - Winter 2014 to Winters 2012 and 2013. MCP ($/MWh) Winter 2012 Winter 2013 DA Regulation 9.3% 63.8% DA Spinning 24.4% 107.2% DA Supplemental 110.0% 133.5% RT Regulation RT Regulation Mileage ($/MW) RT Spinning RT Supplemental 18.4% NA 57.4% 240.0% 103.8% 144.9% 259.1% 556.3% 28 Tables 10a-c below summarize hourly statistics of price dispersion characteristics for MISO-wide ancillary service product market clearing prices (MCPs) during the winters of 2012, 2013, and 2014. The maximum hourly Real-Time Ancillary Service prices over the last three winters were observed on January 7th, 2014, in HE 8. Consecutive Operating Reserve scarcity intervals were experience during that hour due to the high load conditions and the forced generation outages. The price for each product approached $1100.00/MWh at that time. Hourly Real-Time LMP exceeded $1700.00/MWh for that hour and fiveminute LMP exceeded $2000.0/MWh for some intervals. Table 10a: MISO Wide Hourly MCP Summary Statistics for the Winter 2012. Winter 2012 MCP ($/MWh) Maximum Average DA Regulation $28.71 $7.50 DA Spinning $12.57 $1.51 DA Supplemental $8.29 $0.89 RT Regulation RT Regulation Mileage ($/MW) RT Spinning RT Supplemental Minimum $2.23 $0.55 $0.50 Standard Deviation $3.25 $1.45 $0.62 Coeffient of Variation* 43.3% 96.3% 69.4% $142.51 $7.48 $1.95 $6.83 91.4% $121.59 $94.19 $1.22 $0.56 $0.17 $0.17 $3.87 $2.16 316.4% 382.6% Minimum $1.27 $0.32 $0.32 Standard Deviation $4.24 $1.35 $0.28 Coeffient of Variation* 60.2% 95.8% 44.6% Table 10b: MISO Wide Hourly MCP Summary Statistics for the Winter 2013. Winter 2013 MCP ($/MWh) Maximum Average DA Regulation $47.32 $7.05 DA Spinning $15.35 $1.41 DA Supplemental $5.00 $0.64 RT Regulation RT Regulation Mileage ($/MW) RT Spinning RT Supplemental $316.00 $7.65 $1.22 $10.77 140.7% $3.21 $0.32 $0.00 $0.31 97.1% $269.61 $232.72 $1.53 $0.48 $0.18 $0.18 $7.11 $5.15 463.5% 1075.1% Standard Deviation $8.41 Coeffient of Variation* 68.5% Table 10c: MISO Wide Hourly MCP Summary statistics for the Winter 2014. Winter 2014 MCP ($/MWh) Maximum Average DA Regulation $106.78 $12.28 Minimum $2.05 29 DA Spinning DA Supplemental RT Regulation RT Regulation Mileage ($/MW) RT Spinning RT Supplemental $70.53 $70.53 $3.12 $2.07 $0.45 $0.45 $4.72 $4.60 151.1% 221.8% $1,359.50 $15.24 $1.38 $39.05 256.3% $5.82 $0.66 $0.06 $0.47 70.9% $1,187.08 $1,100.00 $4.39 $3.70 $0.13 $0.13 $33.90 $32.03 771.6% 865.5% * The Coefficient of Variation is used as a statistical measure of price volatility. 6. Virtual Transactions Virtual transactions are purely financial positions that can be taken in the DayAhead energy market and do not have to be backed by physical generation or load. As per the FERC order approving a revised methodology, Real-Time RSG allocation changed on April 1st, 2011, allocating costs for congestion management to fluctuations impacting a congested area, as well as to market wide deviations. The result of the new RSG allocation methodology was anticipated to lead to reduced virtual trading costs and therefore, increase virtual trading. The chart below shows MISO’s virtual supply and demand volumes in the winters of 2012, 2013, and 2014. Figure 20: Monthly Avg. of Cleared Virtual Load and Cleared Virtual Supply during the Winters of 2012, 2013, and 2014. 6000 Virtual Load Virtual Supply Net 5000 4000 3000 MW 2000 1000 0 -1000 -2000 -3000 Winter 2014 Winter 2013 Winter 2012 Feb-14 Jan-14 Dec-13 Feb-13 Jan-13 Dec-12 Feb-12 Jan-12 Dec-11 -4000 Net is defined as the difference between Cleared Virtual Load and Cleared Virtual Supply. In the winter of 2014, the volumes of cleared virtual demand increased by 18.0%, while cleared virtual supply decreased 0.2%, relative to the respective volumes in winter 2013. Net virtual load, as the difference between cleared virtual load and cleared virtual supply, increased significantly this winter. 30 7. RSG Millions Figure 21: MISO Market Wide RSG Make Whole Payments in Day-Ahead and Real-Time Markets Winters of 2012, 2013 and 2014. 45.00 Real-Time RSG MWP Day-Ahead RSG MWP 40.00 35.00 30.00 $28.31 25.00 20.00 15.00 $5.92 $12.23 10.00 5.00 $2.63 0.00 Dec $11.44 $3.28 $4.37 $1.68 $1.21 $2.62 $2.38 $1.69 $1.92 $4.93 Jan Feb Dec Jan Feb Dec Winter 2012 Winter 2013 Jan $14.86 Feb Winter 2014 *Based on data extracted early May 2014. Values may change due to resettlement. Figure 21 above shows the Day-Ahead and Real-Time RSG uplifted to the market. Both Day-Ahead and Real-Time RSG Make Whole Payments increased substantially in the 2014 winter season. Real-Time RSG Make Whole Payments were impacted by high natural gas prices (see Figure 9 in Section 4), high loading conditions that were driven by the severe winter weather, and heavy congestion. Day-Ahead RSG Make Whole Payments were also impacted by high natural gas prices and by VLR commitments in the South Region. The total of February’s Day-Ahead and Real-Time RSG is the highest for any winter month since the Ancillary Services Market was launched in 2009. Over 60.0% of February’s Real-Time RSG was associated with constraint mitigation, a significant portion of which was for congestion management around the Michigan area. The local congestion was driven by high weather-sensitive loads, and generation and transmission outages. Day-Ahead RSG associated with VLR commitments in February was 63.6% of the total Day-Ahead RSG. Over 90.0% of the Day-Ahead RSG associated with VLR was for the South Region. 31 8. FTR Table 11: MISO FTR Funding and Shortfall Winter 2012 Millions Dec Jan Feb Total * Based FTR Target Credit Alloc. $99 $64 $50 $212 Winter 2013 FTR Funding FTR Target Credit Alloc. FTR Target Credit Alloc. FTR Funding $99 $64 $50 $212 100% 100% 100% 100% $118 $111 $102 $331 $106 $105 $91 $303 Winter 2014 Funding Percent FTR Target Credit Alloc. FTR Funding Funding Percent 90% 95% 89% 91% $159 $444 $460 $1,062 $157 $444 $446 $1,047 99% 100% 97% 99% on data extracted early April 2013. Values may change due to resettlement. Table11 above shows that the monthly FTR funding levels improved during the winter of 2014. February 2014 had the lowest funding level for the season. February’s funding was impacted by binding constraints caused by West-East transfers, primarily wind-driven, and outages that occurred after the FTR model cutoff. 32 VI. Noteworthy Highlights 1. Membership: South Region Integration After more than two years of intensive planning and training, MISO successfully transitioned a four-state region of the electric grid across the south into MISO’s existing market footprint on December 19th, 2013. The integration, which extends MISO’s operational and market footprints from Manitoba, Canada all the way to the Gulf of Mexico, also adds over 18,000 miles of transmission, approximately 50,000 megawatts of generation capacity, and approximately 30,000 MW of peak load into the MISO footprint and makes MISO one of the largest power grid operators in the world. Amongst other benefits, MISO’s increased scale will drive benefits through expanded options for generation commitment and dispatch from a more diverse set of fuel types. MISO’s increased scale will also drive benefits through improved reliability and reduce regulation and spinning reserve requirements by consolidating balancing authorities. 2. Control Center Facilities On December 10th, 2013, MISO completed the relocation of its operations from the St. Paul, MN facility to the new Eagan, MN facility. In conjunction with the move, MISO modified the designations for the various operating regions. The ‘Carmel’ region is now referred to as the ‘Central’ region and the ‘St. Paul’ region is now referred to as the ‘North’ region. The ‘South’ region continued with its designation. No changes to the physical boundaries of the regions took place. On March 14th, 2014, MISO broke ground for a new operations center in Little Rock, Arkansas. This action marks the next phase of the successful integration of the South region on December 19th, 2013. The new facility will serve as the regional control center for the South region, housing services that include real-time operations, market operations, customer relations, government and regulatory affairs, information technology and administrative support. The operations center is expected to be in service in the spring of 2015. 3. South Region ICT Services The Independent Coordinator of Transmission (ICT) services are now concluded commensurate with the integration of the Entergy system into the MISO market. MISO 33 successfully transitioned as the provider of ICT services for Entergy on December 1st, 2012 conducting, amongst other duties, the Weekly Procurement Process and the processing (i.e. study, coordination, and approval) of generation and transmission outage requests for the Entergy System. 4. Value Proposition With growing energy demands throughout MISO's footprint, MISO’s services help ensure reliable, least-cost delivered energy. MISO’s Value Proposition documents how MISO unlocks billions in annual benefits for the region. On February 13th, 2014, MISO released an updated Value Proposition analysis indicating that MISO’s services provided between $2.1 billion and $3.0 billion in regional benefits in 2013. The benefits were driven by enhanced reliability, more efficient use of the region’s existing transmission and generation assets, and a reduced need for new assets. MISO’s Value Proposition affirms MISO’s core belief that a collective, regionwide approach to grid planning and management delivers the greatest benefits. MISO’s landmark analysis serves as a model for other grid operators and transparently communicates the benefits in everything we do. 34