IMM Quarterly Report: Winter 2018 MISO Independent Market Monitor David Patton, Ph.D. Potomac Economics March 27, 2018
Highlights and Findings: Winter 2018 The MISO markets performed competitively this winter. Natural gas prices fell by 6 percent over last year, but energy prices increased by 8 percent over the same period due to January weather-related events. Market power mitigation was infrequent and offers were competitive. In January, extremely cold temperatures throughout the footprint affected gas prices, generation outages and performance, and energy prices. Significant fuel price volatility in late December and early January contributed to high congestion and price volatility. On January 17 and 18, MISO declared Maximum Generation Events and took a number of emergency actions in the South. Temperature-related forced outages contributed to tight conditions on multiple days. LMRs were scheduled and deployed on both days and MISO took a number of other emergency actions on January 17. Reliability was maintained, but prices did not efficiently reflect conditions. A new wind output record of 15.0 GW was set on January 17. Transmission congestion was significantly higher this winter than last year. -2-
Quarterly Summary Change 1 Change 1 Value Prior Qtr. Prior Year Value Prior Qtr. Prior Year RT Energy Prices ($/MWh) $31.13 4% 8% FTR Funding (%) 101% 100% 99% Fuel Prices ($/MMBtu) Wind Output (MW/hr) 7,217 14% 5% Natural Gas - Chicago $3.08 7% -6% Guarantee Payments ($M) 4 Natural Gas - Henry Hub $3.06 4% -6% Real-Time RSG $17.7-25% 50% Western Coal $0.70 4% 4% Day-Ahead RSG $11.1 12% -19% Eastern Coal $1.51 1% -2% Day-Ahead Margin Assurance $13.7 16% 27% Load (GW) 2 Real-Time Offer Rev. Sufficiency $1.0-43% -21% Average Load 79.4 9% 5% Price Convergence 5 Peak Load 106.1-8% 4% Market-wide DA Premium 2.4% -3.0% 0.2% % Scheduled DA (Peak Hour) 98.7% 98.4% 99.0% Virtual Trading Transmission Congestion ($M) Cleared Quantity (MW/hr) 15,519 4% 30% Real-Time Congestion Value $384.4-15% 29% % Price Insensitive 35% 30% 30% Day-Ahead Congestion Revenue $231.4 14% 56% % Screened for Review 1% 1% 1% Balancing Congestion Revenue 3 $.6 $12.8 $11.4 Profitability ($/MW) $1.32 $0.83 $0.55 Ancillary Service Prices ($/MWh) Dispatch of Peaking Units (MW/hr) 831 1023 444 Regulation $9.98-1% 5% Output Gap- Low Thresh. (MW/hr) 82 95 92 Spinning Reserves $2.69-7% 35% Other: Supplemental Reserves $1.32 80% 80% Key: Expected Notes: Monitor/Discuss Concern 1. Values not in italics are the value for the past period rather than the change. 2. Comparisons adjusted for any change in membership. 3. Net real-time congestion collection, unadjusted for M2M settlements. 4. Includes effects of market power mitigation. 5. Values include allocation of RSG. -3-
Highlights for Winter 2018 Winter Peak: Late Dec 17 / Early Jan 18 (Slides 12, 13, 20, 21, 22) Gas prices rose 15 percent in January from the prior year, contributing to a 40 percent increase in energy prices. Extremely cold weather throughout the footprint from January 1 to 4 led to: MISO-wide Cold Weather Alerts and Conservative Operations ending Jan 6. Winter load peaked on January 2 at 104.7 GW, but was lower than the all-time winter peak load of 109.3 GW during the 2014 Polar Vortex. Fuel-related generation outages and more than 4 GW of generation that could only be used in an emergency contributed to tight operating conditions on several days. 14 intervals of operating reserve shortages occurred with average prices of $501/MWh. Multiple gas pipeline restrictions and high gas prices occurred. Dual-fuel capable units switched to burn oil that was cheaper than gas. Cold weather in late December also led to gas price volatility. The Ventura hub price was as high as $67.50 on three days and affected many units. We consulted with multiple participants on generation fuel costs for references and no inappropriate mitigation occurred. -4-
Highlights for Winter 2018 Winter Peak: Jan 17 th -18 th in MISO South (Slides 12, 14, 15, 16, 17, 18) Unusually cold weather in the South on January 17 and 18 led to a record winter peak in the South of 32.1 GW on January 17 and emergency events. Conditions were extremely tight on January 17 from 6 AM to 1 PM: MISO s load forecast in the early morning showed a significant capacity deficiency by 9 AM, prompting MISO to declare a Max Gen Alert starting 5 AM. The actual load was well below the forecast by the peak hours (7 to 9 AM) due to voluntary load curtailments and the initial response from LMRs called at 6 AM. However, forced outages rose from 5 GW at midnight to almost 7.5 GW by 8:30. MISO relaxed some of its transmission limits in the South, raising them by roughly 25 percent to increase access to generation. Because load exceeded supply, MISO exceeded the RDT limit for roughly an hour from 6:45 AM to 7:45 AM, by almost 1000 MW at 7:25 AM. MISO scheduled emergency transactions beginning at 7:30 AM that exceeded 1000 MW by 9 AM, allowing it to reduce the RDT flows to below the limit. MISO declared an emergency for the evening peak and for the morning of the 18 th, but conditions were not as tight because some units returned from outage. Given the supply and demand conditions, all of MISO s actions were necessary to keep the lights on in the South. -5-
Highlights for Winter 2018 Winter Peak: Jan 17 th -18 th in MISO South (Slides 12, 14, 15, 16, 17, 18) Day-ahead congestion was much higher than real-time congestion costs. Emergency actions taken on both days resulted in lower real-time congestion. Louisiana Hub day-ahead premium exceeded $1,100 for one hour on Jan 18. Findings regarding LMRs: The LMRs were not obligated to be available (only required in the summer). Long notification times limit LMRs value schedules were low on the 17 th in the morning peak. MISO declared the event early on Jan 18 to secure them. It is difficult to tell from observing the load the extent of the LMR response. This event may underscore the value of reconsidering how MISO quantifies the capacity credit for LMRs in the PRA. Findings regarding prices during the event on the 17 th : Prices were high when the RDT was violated due to the RDT demand curve. Emergency procedures raised prices slightly, but much lower than optimal: ELMP did not properly account for RDT flows. The emergency price floor set by a unit offer can be too low or too high. Adding the regional reserve requirements and pricing any shortages that occur will lead to fully efficient prices. -6-
Highlights for Winter 2018 High Congestion (Slides 10, 23, 24, 25, 26) Day-ahead and real-time quarterly congestion costs increased 56 and 29 percent, respectively, over last year. High gas volatility days early in the month, record-high wind production, and emergency conditions the South in January were contributing factors. More than one quarter of all day-ahead congestion occurred on January 17 and January 18. In January, MISO incurred $162 million in real-time congestion in the Midwest and $64.5 million in the South. More than 40 percent of real-time congestion was attributable to market-tomarket constraints. One constraint impacted by a PJM pseudo-tied unit contributed to $36 million in congestion in the quarter, and PJM paid MISO $9.6 million. Wind units in PJM had the majority of relief on a constraint that contributed to $29 million in real-time congestion (which is difficult to manage). -7-
Submittals to External Entities and Other Issues We made two new referrals and responded to FERC questions related to prior referrals and continued to meet with FERC on a weekly basis. A participant provided false information in a Reference Price Consultation. We also referred a matter related to PJM s failure to perform CMP Study 1 and MISO is evaluating impacts for possible resettlement. We responded to several data requests related to prior referrals. We made several notifications of other potential Tariff violations. We participated in the following FERC dockets. We filed a protest related to MISO s refiling of its capacity market in an attempt to remedy the design flaw that causes inefficiently low prices. FERC affirmed the design flaw, but the Order ignores the evidence we and others filed. We assisted MISO in the Order 831 Compliance filing (increasing the Offer Cap), and a modification to the Resource Adequacy Construct to include external resource zones in the PRA. We submitted comments in the Fast-Start Pricing dockets in NY and PJM. -8-
Submittals to External Entities and Other Issues We participated in a number of stakeholder discussions and working groups. At the MSC and at the ERSC, we discussed concerns with the current RDT commitment tool and the need for improvements to reduce inefficient commitments. We continued to work with MISO and stakeholders on proposed improvements to the Uninstructed Deviation Thresholds (SOM 2012-2) and improved incentives for PVWMP (SOM 2016-5). In February, we presented at the RASC meeting to prepare stakeholders for the upcoming PRA. We participated in the February PJM-MISO JCM Meeting. -9-
$/MWh Natural Gas Price ($/MMBtu) Day-Ahead Average Monthly Hub Prices Winter 2016 2018 $70 $7.0 $60 $50 Mean Gas Price Arkansas Hub Minnesota Hub Michigan Hub Texas Hub Louisiana Hub Indiana Hub $6.0 $5.0 $40 $4.0 $30 $3.0 $20 $2.0 $10 $1.0 $0 Dec Jan Feb Dec Jan Feb Dec Jan Feb Winter 2016 Winter 2017 Winter 2018-10- $0.0
All-In Price ($/MWh) Natural Gas Price ($/MMBtu) All-In Price Winter 2016 2018 $50 $40 Capacity Ancillary Services Uplift Energy (Shortage) Energy (Non-shortage) Natural Gas Price $10 $8 $30 $6 $20 $4 $10 $2 $0 16 17 18 J F M A M J J A S O N D J F M A M J J A S O N D J F Mo. Avg. 2016 2017 2018 $0-11-
Average Temperatures on January Cold Days Hist. Avg.* 1 2 3 4 January 5 16 17 18 19 Midwest Minneapolis 14.2-7.2 4.1 3.1-1.4-4.0 1.7 14.4 30.7 35.3 Milwaukee 21.8-1.1 4.6 12.6 5.9 5.1 20.5 15.9 26.0 35.2 Detroit 25.9 8.4 6.7 10.8 8.7 1.5 13.1 12.7 20.7 29.7 Indianapolis 27.2-3.7-1.4 12.8 4.6 0.7 2.3 8.3 19.9 30.1 South Little Rock 38.9 15.8 16.7 24.0 24.9 29.4 17.0 14.7 24.0 34.3 New Orleans 53.7 31.3 31.5 38.2 38.2 39.7 37.3 27.7 33.4 43.6 Cold Weather Alert (MISO) Conservative Ops in MISO (Jan 2-5) and South (Jan 16,19) Max Gen Event in South * Historical Avg. is average of those days' average temperature from 2008-2017. -12-
Cold Weather Alerts and Conservative Ops January 1-4 Price ($/MWh) $360 $240 $120 DA SMP RT SMP DA F'cast Load DA Sched. Load $0 110,000 100,000 90,000 Load (MW) January 1 January 2 January 3 January 4 Jan. Conservative 1 OPS 2 Cold Weather Alert 3 Actual Load 4 80,000-13-
Load (MW) Price ($/MWh) Conservative Ops and Max Generation Event in MISO South January 17 & 18 $1000 $800 $600 $400 $200 $0 DA Load Weighted Price RT Load Weighted Price DA F'cast Load DA Sched. Load Actual Load 35,000 31,000 27,000 23,000 19,000 January 16 January 17 January 18 January 19 15,000 August MaxGen 10 Event (South) 17 Conservative 18 Ops (South) 10-14-
MW MW 52,000 50,000 48,000 46,000 44,000 42,000 40,000 38,000 36,000 34,000 32,000 30,000 28,000 26,000 24,000 22,000 MISO South Generation and Load January 17 Available Supply Load 7300 MW 7000 MW Supply w/out Emer. Purchases Total Supply (incl. Imports & RDT) Total Generation + RDT Scheduled LMR Cancelled Scheduled LMR Planned Outages Forced Outages Derates 4100 MW 9200 MW 3 5 7 9 11 13 15 17 19 21 23 Jan. 17 Generation lost to Outages and Derates 1,000 500 0-15-
MW MW MISO South Generation and Load January 17 Maximum Generation Event 36,000 34,000 Available Supply MTLF 32,000 30,000 28,000 Load Supply w/out Emer. Purchases 26,000 24,000 22,000 Scheduled LMR 5 6 7 8 9 10 11 12 13 January 17 400 200 0-16-
MW MISO South Generation and Load January 18, 2018 52,000 50,000 48,000 46,000 44,000 42,000 40,000 38,000 36,000 34,000 32,000 30,000 28,000 26,000 24,000 22,000 20,000 18,000 Total Supply (incl. Imports & RDT) Available Supply Total Generation + RDT 0 3 6 9 12 15 18 21 Jan. 18-17- Load Scheduled LMR Cancelled Scheduled LMR Planned Outages Forced Outages Derates 1,000 500 0
Pricing on January 17 During Maximum Generation Event $1,000 $900 Efficient LMP with Emergency and Shortage Pricing (30 min reserves) $800 $700 $600 Correct Emergency Pricing in ELMP $500 $400 $300 $200 Actual LMP Ex Ante LMP $100 Exceeded RDT Emergency Purchases $0 6:00 6:30 7:00 7:30 8:00 8:30 9:00 9:30 10:00 10:30 11:00 11:30 12:00-18-
$/MWh Monthly Average Ancillary Service Prices Winter 2017 2018 $14 $12 $10 $8 $6 Regulation Price (exclude shortages) MCP Impact from Reg Shortages Spinning Reserve Price (exclude shortages) MCP Impact from Spin Shortages Supp Reserve Price (exclude shortages) MCP Impact from OR Shortages Day-Ahead Premium Winter Average of Five Years $4 $2 $0 -$2 D J F M A M J J A S O N D J F D J F M A M J J A S O N D J F D J F M A M J J A S O N D J F 2016 2017 2018 2016 2017 2018 2016 2017 2018 Regulation Spinning Reserve Supplemental Reserve -19-
$/MMBtu MISO Fuel Prices 2016 2018 $5.5 $5.0 $4.5 $4.0 $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 J F M A M J J A S O N D J F M A M J J A S O N D J F 2016 2017 2018 16 2016 2017 2018 Winter Average 17 2016 2017 2018 18 Winter Average Chicago NG $2.10 $3.26 $3.08 Henry NG $2.04 $3.25 $3.06 9.01 IB Coal $1.36 $1.54 $1.51 PRB Coal $0.55 $0.67 $0.70-20-
$/MMBtu MISO Fuel Prices Winter 2018 $16.0 $68 $14.0 $12.0 $10.0 $8.0 $6.0 $4.0 $2.0 $0.0 Oil IB Coal PRB Coal Ventura Gas Henry Hub Gas Chicago Gate Gas 1 5 9 13 17 21 25 29 1 5 9 13 17 21 25 29 1 5 9 13 17 21 25 December 2017 January 2018 February 2018-21-
Adjusted Degree Days Load (MW) Load and Weather Patterns Fall 2016 2018 1,800 1,500 1,200 900 600 300 0 16 17 18 15 16 17 16 17 18 16 17 18 Monthly Avg. Dec Jan Feb 130,000 120,000 110,000 100,000 90,000 80,000 70,000 60,000 CDDs HDDs Note: Midwest degree day calculations include four representative cities in the Midwest: Indianapolis, Detroit, Milwaukee and Minneapolis. The South region includes Little Rock and New Orleans. -22- Average Load Historical Avg. Peak Load
Day-Ahead Congestion, Balancing Congestion and FTR Underfunding, 2016 2018 $200 M $175 M $150 M $125 M $100 M $75 M $50 M $25 M $0 M Winter Totals 2017 2018 Balancing Congestion Revenue ($11.4 M) $0.6 M DA Congestion Revenues $148.5 M $231.4 M FTR Surplus (Shortfall) ($3.0 M) $6.6 M FTR Funding (%) 99.1% 101.3% J F M A M J J A S O N D J F M A M J J A S O N D J F 2016 2017 2018 $15M $0M -$15M -23-
Congestion Value ($ Millions) Value of Real-Time Congestion Winter 2017 2018 $300 $250 $200 Totals Win. 17 Fall 17 Win. 18 Midwest 201.4 M 370.3 M 292.8 M Transfer Constraints 3.4 M 7.0 M 10.4 M South 92.1 M 76.0 M 81.3 M Total RT Value 296.9 M 453.3 M 384.4 M DA Congestion Revenue 148.5 M 203.4 M 231.4 M $150 $100 $50 $0 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018-24-
Market-to-Market Testing and Activation Delay Congestion Costs: 2017-2018 Congestion Value ($ Million) $160 $140 $120 $100 $80 $60 $40 Congestion ($ Million) Categories (NMRTO) Winter 2017 Spring 2017 Summer 2017 Fall 2017 Winter 2018 Never classified as M2M (PJM) $37.1 $29.6 $7.1 $73.3 $20.3 Never classified as M2M (SPP) $11.1 $57.8 $22.5 $30.3 $6.5 M2M Testing Delay (PJM) $8.8 $15.2 $15.8 $19.9 $4.8 M2M Testing Delay (SPP) $1.9 $2.4 $1.3 $5.1 $0.1 $20 $0-25-
Millions MISO Congestion Value and JOA Settlement Constraints Impacted by Pseudo-Ties $90 $80 $70 $60 $50 $40 $30 $20 $10 JOA Payment - Uplift JOA Payment - Transfer Real-Time Congestion Period with New PJM Pseudo-Ties Average Congestion Per Quarter Before Pseudo Ties $22.4 M After Pseudo Ties $38.3 M Percentage Increase 71% $0 1 2 3 4 1 2 3 4 1 2 3 4 1 2015 2016 2017 2018-26-
RDT Flow South to North (MW) Real-Time Hourly Inter-Regional Flows 2017-2018 4,000 3,000 2,000 Hourly Average Daily Average Monthly Average 2500 MW RDT Limit 1,000 0-1,000-2,000-3,000-4,000-3000 MW RDT Limit M A M J J A S O N November December January February Monthly Avg. -27-
Quantity (MW) Wind Output in Real-Time and Day-Ahead Monthly and Daily Average 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0-2,000 Winter Avg. 2016 2017 2018 Net Virtual Supply 562 452 86 Day-Ahead Wind 5,094 5,951 6,042 Real-Time Wind 5,731 6,903 7,217 J F M A M J J A S O N D J F 1-7 8-14 15-21 22-31 1-7 8-14 15-21 22-31 1-7 8-14 15-2122-28 2017 2018 Dec. 2017 Jan. 2018 Feb. 2018 Monthly Average Daily Average -28-
$/MWh Day-Ahead and Real-Time Price Convergence Winter 2017 2018 $60 $50 $40 $30 $20 $10 $0 -$10 Average Price Difference Absolute Difference RT RSG Rate Average RT Price DA RSG Rate Average DA Price DARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDART 17 18 D J F M A M J J A S O N D J F Mo. Avg. 2016 2017 2018 Average DA-RT Price Difference Including RSG (% of Real-Time Price) Indiana Hub 1-3 1 0 1-4 0-3 5-3 1-16 3 2 4-6 -8 Michigan Hub 1 0 2 1 1-6 -1-1 0-3 1-11 -1 0 2-2 1 Minnesota Hub 0-1 -6 3 3-1 -5 1 5-7 2-7 -10 3 0 3-6 WUMS Area -3 0-6 -1-2 3-1 3 3-8 3-11 0 0 2 2-3 Arkansas Hub 1-2 0 1 3-3 0 2 5-7 2-2 5-3 1-7 -1 Texas Hub 1-1 2-2 3-2 3 4-1 -1 3 1 8-6 4-5 -1 Louisiana Hub 1-9 1 1-2* 2-4 3-1 -9-6 -1 7-5 5 3* 3 * Excluding Feb. 7, 2017 and Jan. 17-18, 2018. -29-
100.4 103.9 101.8 103.1 103.1 106.4 102.9 100.3 102.3 103.2 102.2 102.9 97.4 103.0 101.4 102.1 101.2 102.3 98.7 98.4 98.0 97.8 98.0 98.3 97.5 97.0 97.8 99.5 97.3 98.0 98.9 97.6 98.6 98.8 98.1 97.8 98.7 99.1 98.7 98.9 99.2 98.7 99.1 98.5 99.3 100.2 99.6 99.9 98.9 98.8 98.6 99.2 98.7 98.6 Share of Actual Load Day-Ahead Peak Hour Load Scheduling Winter 2017 2018 104% 100% 96% 92% 88% Net Virtual Supply Net Virtual Load 84% Higher DA NSI Lower DA NSI Price-Based Load Fixed Load 80% 16 17 18 D J F M A M J J A S O N D J F Monthly Avg. 2016 2017 2018 Share of Actual Load (%) All Hours Peak Hours Midwest Peak Hours South -30-
Average Hourly Volume (MW) Supply Demand 28,000 24,000 20,000 16,000 12,000 8,000 4,000 0 4,000 8,000 12,000 16,000 20,000 24,000 28,000 32,000 Virtual Load and Supply Winter 2017 2018 16 17 18 D J F M A M J J A S O N D J F 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018 Mo. Avg. Midwest -31- Uncleared Cleared, Price Sensitive Cleared, Price Insensitive Cleared, Screened Transactions 16 2017 2018 South
Average Hourly Volume (MW) Supply Demand Virtual Load and Supply by Participant Type Winter 2017 2018 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 16 17 18 D J F M A M J J A S O N D J F 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018 Mo. Avg. Financial-Only Participants Uncleared Cleared, Price Sensitive Cleared, Price Insensitive Cleared, Screened Transactions 16 2017 2018 Generators / LSEs -32-
Total Profits Virtual Profitability January 1-20 $12,000,000 $8,000,000 $4,000,000 Net MEC Net MCC Net MLC $0 -$4,000,000 Date -33-
Profits per MW Total Profits (Millions) Virtual Profitability Winter 2017 2018 $45 M $40 M $35 M $30 M $25 M $20 M $15 M $10 M $5 M $0 M -$5 M Supply Demand Gross 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018 Percent Screened Demand 0.8 1.1 1.2 1.1 0.9 1.3 1.4 2.1 2.8 1.4 1.2 0.5 1.7 1.4 0.7 0.6 2.3 0.6 Supply 0.4 0.4 0.4 0.6 0.3 0.2 0.4 0.4 0.5 0.3 0.1 0.2 0.5 0.4 0.2 0.3 0.9 0.2 Total 0.6 0.7 0.8 0.8 0.6 0.7 0.9 1.2 1.6 0.8 0.7 0.3 1.0 0.9 0.5 0.4 1.6 0.4 $4 $2 $0 -$2-34-
Ramp Up MCP ($ per MWh) Day-Ahead and Real-Time Ramp Up Price 2016 2018 $2.00 $1.80 $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 Average RT Ramp Up MCP Average DA Ramp Up MCP J A S O N D J F M A M J J A S O N D J F 2016 2017 2018-35-
Share of Market Intervals Interface Pricing with PJM (Common Interface) Winter 2018 4.0% 3.5% 3.0% 2.5% 2.0% 1.5% 1.0% 0.5% 0.0% Difference Relative to Ideal Price -36-
Average Hourly MW In-Merit MW (%) 4,400 4,000 3,600 3,200 2,800 2,400 2,000 1,600 1,200 800 400 0 Peaking Resource Dispatch 2016 2018 Real-Time Local Voltage Real-Time Capacity Percent In-Merit Real-Time Congestion Committed Day-Ahead 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% -37-
RSG Payments ($ Millions) Day-Ahead RSG Payments 2016 2018 $20 $15 Sum of 2018 Winter (Millions) Midwest South Total Fuel-Adjusted Fuel-Adjusted RSG: RSG: VLR $1.18 $3.79 $4.97 Fuel-Adjusted Fuel-Adjusted RSG: RSG: Capacity $2.38 $2.01 $4.39 Total Nominal RSG RSG $4.18 $6.88 $10.82 RSG Mitigation $0.24 $10 $5 $0 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018-38-
RSG Payments ($ Millions) Real-Time RSG Payments 2016 2018 $20 $15 Sum of 2018 Winter (Millions) Midwest South Total Fuel-Adjusted RSG: VLR $0.01 $0.38 $0.39 Fuel-Adjusted RSG: Congestion $0.64 $0.73 $1.36 Fuel-Adjusted RSG: RDT $0.30 $1.16 $1.46 Fuel-Adjusted RSG: Capacity $8.32 $0.82 $9.15 Total Nominal RSG $13.59 $4.00 $17.59 RSG Mitigation $0.01 $0.07 $0.09 $10 $5 $0 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018-39-
RSG ($M) # Days Units Committed for RDT RDT Commitment RSG Payments 2016 2018 $7.0M $6.0M $5.0M $4.0M $3.0M $2.0M $1.0M $0.0M RSG to South Units RSG to Central/ North Units # Days Units Committed for RDT J F M A M J J A S O N D J F M A M J J A S O N D J F 2016 2017 2018 30 27 24 21 18 15 12 9 6 3 0-40-
Uplift Payments ($ Millions) Volatility (Average Interval Price Change) Price Volatility Make Whole Payments 2016 2018 $12 $9 DAMAP (Midwest) RTORSGP (Midwest) DAMAP (South) RTORSGP (South) SMP Volatility LMP Volatility $12 $9 $6 $6 $3 $3 $0 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018 $0-41-
Share of Capacity Generation Outage Rates 2015 2016 50% 45% 40% 35% 30% Winter 2016 2017 2018 North South North South North South Short-Term Unplanned Outages 4.1% 3.1% 4.7% 2.7% 4.1% 3.0% Long-Term Unplanned Outages 3.9% 2.4% 5.1% 7.6% 5.5% 6.1% Planned Outages 5.3% 6.7% 6.4% 7.8% 7.5% 10.6% Total 13.2% 12.2% 16.2% 18.0% 17.1% 19.7% 25% 20% 15% 10% 5% 0% 16 17 18 D J F M A M J J A S O N D J F Winter 16 2017 2018-42-
Share of Capacity Generation Outage Rates South: 2015 2016 50% 45% 40% 35% Winter 2016 2017 2018 Short-Term Unplanned Outages 3.1% 2.7% 3.0% Long-Term Unplanned Outages 2.4% 7.6% 6.1% Planned Outages 6.7% 7.8% 10.6% Total 12.2% 18.0% 19.7% 30% 25% 20% 15% 10% 5% 0% 16 17 18 D J F M A M J J A S O N D J F Winter 16 2017 2018-43-
Output Gap (MW) Share of Actual Load Monthly Output Gap 2016 2018 250 225 200 175 150 125 100 75 50 25 0 Low Threshold High Threshold Share of Actual Load 16 17 18 D J F M A M J J A S O N D J F 0.4% 0.3% 0.2% 0.1% 0.0% Mo. Avg. 16 2017 2018 High Threshold Results by Unit Status (MW) Offline 13 6 0 24 13 6 5 11 14 4 2 1 12 0 0 0 0 0 Online 13 20 23 29 23 19 27 24 55 20 16 10 24 15 26 19 33 14 Low Threshold Results by Unit Status (MW) Offline 14 6 0 25 13 6 5 11 14 4 2 2 16 0 0 0 0 0 Online 60 63 88 113 72 46 100 79 130 69 63 44 114 68 86 72 113 63-44-
Hours MW Mitigated Day-Ahead And Real-Time Energy Mitigation 2017 2018 200 180 160 140 120 100 80 60 40 20 0 161718 J F M A M J J A S O N D J F 161718 J F M A M J J A S O N D J F Mo. Total DA Hours Mitigated, NCA RT Hours Mitigated, NCA DA Hours Mitigated, BCA RT Hours Mitigated, BCA Combined MW Mitigated 2017 2018 Mo. Total BCA 2017 2018 NCA 1000 900 800 700 600 500 400 300 200 100 0-45-
RSG Mitigation Dollars (Thousands) Mitigated Unit-Days Day-Ahead and Real-Time RSG Mitigation 2016 2018 $1000 $800 $600 $400 DA RSG Mitigated RT RSG Mitigated Combined Unit-Days 120 90 60 $200 30 $ 16 17 18 D J F M A M J J A S O N D J F Mo. Avg. 16 2017 2018 0-46-
List of Acronyms AMP Automated Mitigation Procedures BCA Broad Constrained Area CDD Cooling Degree Days CMC Constraint Management Charge DAMAP Day-Ahead Margin Assurance Payment DDC Day-Ahead Deviation & Headroom Charge DIR Dispatchable Intermittent Resource HDD Heating Degree Days ELMP Extended Locational Marginal Price JCM Joint and Common Market Initiative JOA Joint Operating Agreement LAC Look-Ahead Commitment LSE Load-Serving Entities M2M Market-to-Market MSC MISO Market Subcommittee NCA Narrow Constrained Area ORDC Operating Reserve Demand Curve PITT Pseudo-Tie Issues Task Team PRA Planning Resource Auction PVMWP Price Volatility Make Whole Payment RAC Resource Adequacy Construct RDT Regional Directional Transfer RSG Revenue Sufficiency Guarantee RTORSGPReal-Time Offer Revenue Sufficiency Guarantee Payment SMP System Marginal Price SOM State of the Market TLR Transmission Line Loading Relief TCDC Transmission Constraint Demand Curve VLR Voltage and Local Reliability WUMS Wisconsin Upper Michigan System -47-