miso 2018 summer assessment report market and operations … summer assessment... · 2018. 10....

MISO 2018 Summer Assessment Report

Market and Operations Analytics

September 2018

2

Table of Contents

I. Executive Summary .................................................................................................. 3 II. Resource Assessment Analysis ............................................................................... 5 III. Market Demand ........................................................................................................ 6

1. Summer Temperatures .................................................................................................... 6

2. Total Real-Time Energy ................................................................................................... 7

3. System-wide and Regional Load ..................................................................................... 7

4. Load Duration Curve Analysis ........................................................................................10

IV. Market Supply ......................................................................................................... 11

1. Generation Resource Analysis .......................................................................................11

2. Generation Outages .......................................................................................................17

V. Market Evaluation and Impacts .............................................................................. 19

1. Price Analysis .................................................................................................................19

2. Price Convergence and Comparative Price Analysis ......................................................22

3. Real-Time Interface Prices at MISO, PJM and SPP .......................................................24

4. Virtual Transactions ........................................................................................................28

5. RSG ...............................................................................................................................29

6. FTR ................................................................................................................................30

3

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. This report provides an assessment of the MISO markets during the 2018 summer period (June, July and August of 2018). Data from the previous two summer seasons are included for comparison. Overall, temperatures averaged around 1°F above normal for this summer. Both June and August were warmer than last summer while July was unseasonably cooler. Average system load weighted temperatures throughout the summer were comparative to the levels seen in Summer 2016. On June 3rd, 2018 a local transmission system emergency event in the South region was caused by severe weather moving across the footprint. The next day, on June 4th, MISO issued Conservative Operations and then a local Maximum Generation Alert. On July 5th MISO declared Conservative Operations, and a Maximum Generation Alert for North and Central regions, due to higher than forecasted load. Also, challenging weather conditions adversely impacted load and wind forecasting accuracy on a number of days. The market-wide summer peak load of 121.6 GW was attained on June 29th, 2018, which was about 1 GW higher than last summer’s peak load. Historically the MISO market-wide summer peak occurs during the third week of July. This year’s peak in late June was representative of the volatility in temperature and weather throughout this summer. The average summer load was 86.6 GW, which was 4.7% higher than the previous summer, impacted by the warmer weather in June and August of this year. The average load was close to the level observed in Summer 2016, which is consistent with the observed average temperature also being close to that in Summer 2016. During the peak load hour in Summer 2016 the capacity margin was about 5.1%, while this summer the margin in the peak hour was 4.1%. The shrinking capacity margin poses a challenge for MISO operations and tests the resilience of the MISO footprint. Large steam unit retirements and increasing forced outage rates associated with ageing units are the largest contributors to the tighter capacity margins. This trend is expected to continue and the new capacity planned to come online in the future is comprised of an increasing amount of intermittent resources such as wind and solar. Energy prices increased 8.1% compared to last summer, and 5.8% relative to Summer 2016. The average of monthly Day-Ahead LMPs for Summer 2018 was $31.39/MWh, and the average of monthly Real-Time LMPs was $30.85/MWh. The higher demand and local congestion, particularly in June and August impacted the LMPs. Natural gas prices remained below $3.00/MMBtu, decreasing 1.5% relative to last summer. Chicago Citygate and Henry Hub gas prices averaged $2.76/MMBtu and $2.89/MMBtu, respectively. Illinois Basin coal prices increased 6.6%, while Powder River Basin coal prices increased 9.6%, compared to Summer 2017.

4

In Summer 2018, coal-fired resources continued to be the largest contributors of

energy in MISO’s generation fleet, providing 47.5% of the total real-time energy production. Natural gas resources accounted for 24.2% of total MISO generation, and nuclear units contributed 14.9% of the total generation for Summer 2018.

Registered wind capacity has consistently grown in the MISO market for the last three summers. The registered wind capacity in Summer 2018 was 18.2 GW up from 16.8 GW and 15.9 GW, respectively for summers of 2017 and 2016. Following the seasonal trend, wind outputs were relatively low during the summer months. On average this summer wind accounted for 5.5% of MISO’s total energy, up from 5.2% in Summer 2017. The average hourly wind output was 4,085 MW increasing 11.4% compared to last summer. Despite the increase relative to last year the volatile weather throughout this summer challenged wind forecasting models as well as real-time operations. For example the lowest instantaneous wind output recorded this summer was 1 MW on July 29th, 2018. The hourly minimum wind output was 128 MW on July 28th, 2018 HE 20.

The average forced generation outages for this summer were 11.6 GW, which

was a decrease of 3.8% compared to last summer. Average planned outages were 6.2 GW, which was a decrease of 14.4% over the same time period. The average over the past 3 summers was 13.4 GW for forced outages and 6.4 GW for planned outages.

At the MISO-PJM seam, the new 10 node common interface went live on June 1st,

2017. The objective of the new interface definition was to mitigate the congestion overlap issue between MISO and PJM. The hourly average of MISO’s PJM Interface Real-Time LMP was $28.93/MWh, while for PJM’s MISO Interface the average was $27.94/MWh; a difference of $0.99/MWh. Comparing with summer 2017, the interface prices for both RTOs increased.

The total Real-Time RSG this summer was about $22.9 million, an increase of

44.3% in comparison to last summer. While, Day-Ahead RSG decreased by 42.2% to about $5.4 million. Several factors contributed to the higher Real-Time RSG this summer, including wind, higher load due to warmer than normal weather, and commitments needed due to generator outages.

In late August MISO instituted a new Operating Guide creating a new VLR load pocket in the South region. The VLR requirements are anticipated to result in additional resource commitments in the pocket, and thus an associated increase in RSG. Further, MISO implemented a market design change to improve its procurement of reserves in MISO South, by applying the Reserve Procurement Enhancement (RPE) to the RDT. This change accounts for the deliverability of reserves, and impacts the zonal reserve market clearing price.

Overall, despite some challenging weather conditions MISO’s reliability, markets

and operational functions performed well during Summer 2018.

5

II. Resource Assessment Analysis

Table II-1: Monthly peak demand and hours for Summer 2018

Jun-18 Jul-18 Aug-18

Load Jun 29th, HE16 Jul 13th, HE17 Aug 27th, HE16

Instantaneous Peak Load 121,563 116,599 116,986

Reserve Requirement 2,410 2,410 2,410

Peak Load Obligation 123,973 119,009 119,396

Capacity

Real-Time Emergency Offer* 162,758 162,165 159,468

(-) Outages 16,906 16,335 16,956

(-) Offer reduction& Wind Derates 18,144 26,119 21,068

(+) Net Imports 6131 7,511 6,889

(+) Non-LMR BTMG 1,193 1,253 1,439

(-) Online Stranded 4,396 1,556 2,094

(-) Emergency Ranges 1,596 1,467 1,456

Real-Time Accessible Capacity 129,040 125,453 126,222

Capacity Margin (%)** 4.1% 5.4% 5.7% Table II-1 shows the monthly peak load obligation and capacity margin for Summer 2018. This summer’s instantaneous peak load was 121.56 GW set on June 29th. There were two Maximum Generation Alerts this summer; the first on June 4th and the second on July 5th for the North and Central regions. Figure II-1.1: Demand and Capacity Analysis for the Peak Hour of Summer 2018

162,758

16,906

145,852

18,144

127,708

6,131 1,193 4,396 1,596

129,040 123,973

5,067

Real-TimeEmergency

Offer

Outages AvailableCapacity

OfferReduction&

WindDerates

InternalCapacity

Committed inReal-Time

Net Imports BTMG(Non-LMR)

OnlineStranded

EmergencyRanges

AccessibleReal-TimePeak HourCapacity

Real-TimePeak HourObligation

CapacitySurplus

Values in MW

Figure II-1.1 provides analysis of demand and capacity during the peak demand hour of the 2018 summer season. The peak load obligation was 123,973 MW in HE 16 on June 29th, and the available capacity was 129,040 MW. The capacity margin was 4.1% for that hour.

6

III. Market Demand

1. Summer Temperatures

Summer 2018 was characterized by slightly warmer than normal temperatures1. In particular June and August temperatures were much warmer than normal, and were close to the temperatures seen in Summer 2016.

Figure III-1: MISO System-wide Load-weighted Temperatures for the summer months

Note: For winter months, it is wind chill, for summer months, it is heat index, and for spring and fall, it is temperature.

1 Source: Normal temperature is based on a 30 year average from the NOAA 1981-2010 climatology dataset,

http://www.cpc.ncep.noaa.gov/products/tanal/temp_analyses.php

7

2. Total Real-Time Energy

Figure III-2: Total Real-Time Energy for the summer months of 2016, 2017, and 2018

0

20

40

60

80

100

120

140

160

180

200

Jun Jul Aug Summer-16 Summer-17 Summer-18

TW

h

2016 2017 2018

Figure III-2 above shows total Real-Time energy consumption for June through August for the years 2016 through 2018. Economic conditions and temperature fluctuations are factors that impact the demand. The total energy consumption for Summer 2018 was higher than that in Summer 2017 primarily due to the relatively warmer temperatures this summer.

3. System-wide and Regional Load

Figure III-3.1: System-wide Average and Instantaneous Peak Load for Summer 2016, 2017, and 2018

This summer’s instantaneous peak load of 121.56 GW occurred on June 29th and

was 0.8% higher than last summer’s peak. The load averaged 86.6 GW this summer, increasing 4.6% from last summer and 0.3% from Summer 2016. The warmer weather

8

experienced across the MISO footprint this summer, in particular during the months of June and August impacted the increase in the load.

Figure III-3.2: Average Load by Region for Summer 2016, Summer 2017, and Summer 2018

0

10

20

30

40

50

60

Summer 2016 Summer 2017 Summer 2018

GW

North Central South

For summer 2018, the average load in all 3 regions increased relative to Summer

2017 largely driven by the warmer weather as stated earlier. This summer the average of monthly load in the North region was 18.21 GW, in the Central region it was 44.79 GW and in the South region it was 23.64 GW.

9

Figure III-3.3: MISO Hourly Avg. of RT Load for Summers of 2016, 2017, and 2018

0

20,000

40,000

60,000

80,000

100,000

120,000

6/1 6/8 6/15 6/22 6/29 7/6 7/13 7/20 7/27 8/3 8/10 8/17 8/24 8/31

MW RT Load Summer 2016 RT Load Summer 2017 RT Load Summer 2018

Month RT Load 16 RT Load 17 RT Load 18

Jun 83,140 80,411 84,503

Jul 87,926 86,913 88,129

Aug 88,102 80,923 87,250

3-Mth Avg. 86,424 82,774 86,651

10

4. Load Duration Curve Analysis

The seasonal load duration curve indicates the number of hours during the summer season when Real-Time Load was greater than a given level within the MISO footprint. Figure III-4: The MISO Load Duration Curves during Summer 2016, Summer 2017, and Summer 2018

40

50

60

70

80

90

100

110

120

130

1 181 361 541 721 901 1081 1261 1441 1621 1801 1981 2161

GW

Number of Hours

Figure III-4 shows load duration curves for the Summer 2018 season and the previous two summers.

Summer 2018 464(21.0%) 1183(53.6%) 1876(85.0%) 2208(100.0%) 2208(100.0%)

Summer 2017 267(12.1%) 976(44.2%) 1714(77.6%) 2208(100.0%) 2208(100.0%)

Summer 2016 487(22.1%) 1146(51.9%) 1841(83.4%) 2208(100.0%) 2208(100.0%)

Hours w ith

Load >40GW

Hours w ith

Load >100GW

Hours w ith

Load >85GW

Hours w ith

Load >70GW

Hours w ith

Load >55GW

11

IV. Market Supply

1. Generation Resource Analysis

Figure IV-1.1: Total Generation by Fuel Type2 for the summers of 2016, 2017, and 2018

49.0

%

24.1

%

4.6

%

15.6

%

6.8

%

50.1

%

22.2

%

5.2

%

16.0

%

6.6

%

47.5

%

24.2

%

5.4

% 14.9

%

8.0

%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Coal Gas Wind Nuclear Other


Note: Other is comprised of Hydro, Oil, Other, Pet Coke, and Waste.

Figure IV-1.2: Generation by Fuel Type by Region for Summer 2018

62.6

%

20.7

%

2.0

%

13.6

%

1.1

%

49.2

%

14.7

%

20.1

%

13.5

%

2.5

%

21.0

%

56.5

%

0.0

%

18.1

%

4.4

%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Coal Gas Wind Nuclear Other

Central Region North Region South Region

Figure IV-1.1 shows the total generation by fuel type for Summer 2016, 2017 and 2018. Figure IV-1.2 shows the regional generation by fuel type for Summer 2018.

2 Based on 5-minute unit level generation dispatch target

12

Coal-fired resources, remain the main source of energy in the Central and North Regions. This summer coal generation provided 47.5% of the total real-time energy production for the entire MISO footprint, decreasing slightly relative to Summer 2017. The share of natural gas increased from 22.2% last summer to 24.2% this summer.

Nuclear units are among the lowest cost resources and normally operate at high

capacity factors. Their contribution of the total generation for Summer 2018 was 14.9%, which was a decrease from Summer 2017. The share of nuclear in the South region dropped from 20.7% last summer to 18.1% this summer.

As of August 1st, 2018, the registered wind capacity in MISO was 18,204 MW

and the registered DIR capacity was 15,621 MW. Currently, no significant wind generation exists in the South Region. This summer, on average 5.5% of total MISO energy production came from wind resources, up slightly from 5.2% last summer. The majority of MISO’s wind production is in the North region.

On June 1st, 2011, MISO successfully launched Dispatchable Intermittent

Resources (DIRs), allowing registered intermittent resources to participate in the Real-Time energy market. From Table IV-1.1, the share of MISO’s total wind energy which was produced by DIR units was 88.6% in Summer 2018, while it was 89.1% last summer.

Table IV-1.1: Percent of Wind Generation at MISO for summers 2016, 2017, and 2018 Summer 2016 Summer 2017 Summer 2018

Jun Jul Aug Jun Jul Aug Jun Jul Aug

Wind Energy as a Percentage of

MISO Energy3 5.9% 4.3% 3.6% 7.4% 4.1% 4.0% 7.1% 4.5% 4.9%

DIR Energy as a Percent of Total

Wind Energy

86.7% 87.0% 87.6% 88.8% 89.2% 89.3% 88.0% 88.6% 89.1%

3 Hourly State Estimate Data

13

Figure IV-1.3: Hourly average of Real-Time wind generation4 during summers 2016, 2017, and 2018

3,447 3,667 4,085

21.8% 22.2%

25.9%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000


MW

Registered Wind Capacity Average Wind Generation Capacity Factor

15,889

18,204

16,760

The capacity factor for wind is the ratio of actual wind generation output to the

registered wind capacity. Figure IV-1.3 shows that the capacity factor, registered wind capacity and wind output have grown in the MISO market over the last three summers. The registered wind capacity for this summer was 18,204 MW, an increase of 8.6% from that of last summer. MISO anticipates the continuation of this trend in the coming years due to policy and economic drivers such as the State Renewable Portfolio Standards and Federal Tax Credits. Currently there are 531 projects, representing 89.3 GW of new capacity, in the Generator Interconnection Queue of the following generator type: 47.5% wind, 40% solar, 11.8% gas and 0.7% other.

The hourly wind output for this summer averaged 4,085 MW, an increase of

11.4% from last summer. Wind output exceeded 9,000 MW in 130 hours during the summer of 2018, while last summer it exceeded 9,000 MW in 79 hours. The volatility of the wind generation, measured in terms of the standard deviation, was also higher this summer compared to the previous two summers. This volatility presented challenges to both forecasting models as well as real-time operations.

4 Source: Historical Hourly Wind Data

14

Table IV-1.2: Wind Generation at MISO monthly peak load hours for summers 2016, 2017, and 2018 Summer

2016 Summer

2017 Summer

2018

Peak Load Hour Wind Generation 3,558 1,973 9,382

Wind Generation as % of Peak Load

2.9% 1.6% 7.7%

Table IV-1.2 shows wind generation at the peak load hour for this summer and

the previous summers. The wind generation percentage in the peak load hour was 7.7% of the peak load.

Figure IV-1.4: Average Percentage of time a fuel is at the margin in Real-Time during the summers of 2016, 2017, and 2018

49

.0%

78

.3%

57

.6%

0.2

%

0.2

%

3.4

%

14

.7%

47

.6%

75

.8%

48

.5%

3.3

%

0.1

%

0.3

%

20

.1%28

.2%

51

.1%

33

.5%

3.0

%

0.0

%

0.1

% 3.2

%-10%

10%

30%

50%

70%

90%

110%

CC Coal Gas^^ Hydro Nuclear Oil Wind


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%. ^^Gas excludes Combined Cycle units

Figure IV-1.4 above shows that Coal was the major fuel at the margin, setting Real-Time LMPs 51.1% of the time during Summer 2018. Gas^^ contributed to setting Real-Time prices 33.5% of the time, on average, during Summer 2018. Combined-Cycle plants, which also burn natural gas, were on the margin in 28.2% of the time. Wind was at the margin less often than in the previous two summers.

15

Figure IV-1.5: Average Monthly Generation Fuels Prices: Coal, Natural Gas Spot Prices and Distillate Fuel Oil: Summers 2016, 2017, and 2018

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

$0

$1

$2

$3

$4

$5

Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug

2016 2017 2018

Fuel Oil $/MMbtu

Coal & Gas$/MMbtu

Chicago Citygate Gas Nominal price Henry Hub Gas Nominal price Illinois Basin Coal Nominal price Powder Basin Coal Nominal price Distillate Fuel Oil Nominal price

Note: The fuel prices are publicly available through 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.

Table IV-1.3: Fuel prices for summers 2016, 2017, and 2018 (Unit:$/MMBtu)

Year

Chicage Citygate Hub

Gas Herry Hub

Gas

Illinois Basin Coal

Powder River Basin

Coal Oil

Summer 2016 2.80 2.86 1.36 0.49 11.62

Summer 2017 2.81 2.92 1.30 0.66 12.07

Summer 2018 2.76 2.89 1.39 0.72 17.07

To Summer 2017 -1.7% -1.3% 6.6% 9.6% 41.4%

To Summer 2016 -1.2% 0.9% 2.6% 46.9% 46.9%

16

Fuel supply conditions influence regional fuel market spot prices (Figure IV-1.5). 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. Coal and oil prices in Summer 2018 increased relative to Summer 2017 and Summer 2016.

Summer 2018 average Illinois Basin coal prices increased 6.6% relative to

Summer 2017. The average Powder River Basin prices increased by 9.6% over the same period. The average natural gas prices decreased slightly this summer relative to Summer 2017.

Summer 2018 average oil prices increased 41.4% relative to Summer 2017.

Figure IV-1.6: Total NSI (MWh) during Summer 2018

10%

14%

17%

8%

30%

2%7%

12%

Summer 2018 Total NSI (MWh)

EEI

IESO

MHEB

OTHER

PJM

SOCO

SPP

TVA

Figure IV-1.6 shows that PJM was the largest source for MISO real-time net

scheduled interchanges (NSI) this summer, with a share of about 30%. This represents a decrease from last summer’s NSI from PJM which was 36%. The second and third largest sources continued to be MHEB (Manitoba Hydro) and IESO. The share for TVA increased from 6% last summer to 12% this summer. The total NSI decreased from 16.33 million MWh in Summer 2017 to 13.86 million MWh this summer.

17

2. Generation Outages

Figure IV-2.1 shows the generator outages which occurred during each month of the summers of 2016, 2017 and 2018. Generator Operators are responsible for submitting generator outages, including derates to MISO. MISO evaluates the impact on transmission system reliability and helps to coordinate the rescheduling of planned outages. MISO is also responsible for the development of mitigation procedures surrounding planned generator outages which ensures that the transmission system continues to operate reliably.

Figure IV-2.1: Monthly Avg. of Generation Outages by Types during the Summers of 2016, 2017, and 2018

0%

2%

4%

6%

8%

10%

12%

14%

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Jun-16 Jul-16 Aug-16 Jun-17 Jul-17 Aug-17 Jun-18 Jul-18 Aug-18

Summer-16 Summer-17 Summer-18

MW

Forced Planned Outages as % of total capacity

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 MISO reliability footprint.

The forced and planned outages for this summer in the MISO reliability footprint, on average, were 11,621 MW and 6,225 MW, respectively. The average forced outages decreased by 3.8%, and average planned outages decreased by 14.4%, compared to last summer.

18

Figure IV-2.2: Daily Avg. of Generation Outages by Region during Summer 2018

0

2

4

6

8

10

12

14

Central Region North Region South Region Central Region North Region South Region Central Region North Region South Region

Jun-2018 Jul-2018 Aug-2018

GW

Daily Average Generation Outages and Derates - Reliability Footprint

Forced Planned Derates

Note: Generation outages extracted in the respective reporting months. Forced Outages includes Emergency, Forced, and Urgent. Data includes both MISO market and reliability footprints. Outage data is “point in time” and can change. The chart reflects the data as it resided in the system on the date of extraction. De-rates are based on limits observed in Real-Time and may reflect normal seasonal de-rates in addition to de-rates for maintenance or other operating conditions.

Figure IV-2.2 shows the generator outages and derates by region which occurred

during each month of the summer of 2018. Compared to Summer 2017, the averages of forced outages decreased by 9% and 4% in the Central and South regions, respectively. However in the North region it increased by 79%. The North region average forced outages in July increased from 1.56 GW in 2017 to 3.56 GW in 2018. Compared to Summer 2017 the averages of planned outages increased by 15% and 40% in the Central and South regions respectively, while in the North region it decreased by 29%.

19

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.

Table V-1.1: MISO Hourly Avg. of RT LMP and DA LMP for 3-months of summers 2016, 2017, and 2018

2016 2017 2018

LMP ($/MWh) Day Ahead Real Time

Day Ahead

Real Time

Day Ahead

Real Time

Jun $27.36 $27.42 $29.00 $28.13 $32.42 $31.74

Jul $30.72 $29.73 $30.24 $31.07 $31.30 $29.33

Aug $30.56 $30.75 $27.38 $26.83 $30.44 $31.47

3-Mth Avg. $29.55 $29.30 $28.87 $28.68 $31.39 $30.85

Table V-1.1 shows MISO Hourly Average of RT LMP and DA LMP for 3 months of summers 2016, 2017 and 2018. The 3-month average Day-Ahead LMP for Summer 2018 was $31.39/MWh, which was 8.7% higher and 6.2% higher than the 3-month averages of Summer 2017 and Summer 2016, respectively. The 3-month average Real-Time LMP for the Summer 2018 was $30.85/MWh, which was 7.6% higher and 5.3% higher than 2017 and 2016 summer’s averages, respectively. Prices were higher in 2018 due to a combination of factors. Most notably, the transmission system emergency in June, increased demand in June and August as well as higher coal prices. Figure V-1.1: Average LMP comparison across MISO and Neighboring Markets: Summer 2016, 2017, and 2018

29.531.5

24.9

29.3 29.8

23.5

28.9 28.6

24.7

28.7 27.9

24.3

31.432.8

25.4

30.8 30.7

24.7

$-

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

MISO PJM SPP MISO PJM SPP

Day - Ahead Market Real-Time Market

$/M

Wh


Figure V-1.1 shows the average prices in the Day-Ahead and Real-Time markets

for MISO and our market-to-market partner RTOs during the summers of 2016, 2017, and 2018. Relative to summer 2017, this summer average LMPs across MISO, PJM,

5MISO system-wide prices are based on the hourly average of the hubs.

20

and SPP increased in both the Day-Ahead and Real-Time markets. The relative increase in MISO LMPs was 8.1%, while for PJM it was 12.6% and for SPP it was 2.3%. This is primarily attributed to the hotter weather experienced this summer across the Central and Eastern regions of the United States.

Tables V-1.2, V-1.3 and V-1.4 below summarize MISO-wide ancillary service

product market clearing prices (MCPs) during the summers of 2016, 2017, and 2018.

Table V-1.2: MISO Wide hourly MCP summary statistics for Summer 2016

Summer 2016

MCP ($/MWh) Maximum Average Minimum Standard Deviation

Coefficient of

Variation*

DA Regulation $55.59 $8.81 $1.53 5.15 58.5

DA Spinning $46.36 $3.57 $0.32 4.46 125.0

DA Supplemental $46.36 $2.22 $0.00 4.37 196.6

RT Regulation $160.48 $8.84 $1.17 8.48 96.0

RT Regulation Mileage** ($/MW)

$3.05 $0.38 $0.05 0.26 67.5

RT Spinning $141.09 $2.43 $0.10 6.23 256.1

RT Supplemental $131.27 $1.53 $0.10 5.76 375.6


Summer 2017


Coefficient of

Variation*

DA Regulation $30.42 $10.11 $2.79 4.50 44.51

DA Spinning $21.27 $3.63 $0.32 3.49 96.09

DA Supplemental $21.27 $0.96 $0.24 2.34 243.67

RT Regulation $243.77 $9.38 $1.40 9.47 100.97

RT Regulation Mileage** ($/MW)

$3.33 $0.39 $0.05 0.25 63.96

RT Spinning $226.96 $3.06 $0.06 7.83 255.68

RT Supplemental $213.38 $1.20 $0.06 6.84 572.36

21


Summer 2018


Coefficient of

Variation*

DA Regulation $32.16 $9.48 $2.75 4.29 45.19

DA Spinning $22.72 $2.78 $0.20 2.98 107.22

DA Supplemental $21.72 $0.55 $0.20 1.53 276.84

RT Regulation $157.49 $10.08 $2.87 8.62 85.54

RT Regulation Mileage** ($/MW) $1.88 $0.51 $0.06 0.20 40.47

RT Spinning $72.77 $2.66 $0.01 5.63 211.50

RT Supplemental $72.77 $0.69 $0.01 3.77 546.63 * The Coefficient of Variation is used as a statistical measure of price volatility. **MISO began Frequency Regulation mileage compensation on December 17th, 2012.

Table V-1.5: MISO Wide Ancillary Service Price Comparison - Summer 2018 relative to Summers 2016 and 2017

Relative to Summer 2016 Relative to Summer 2017

DA Regulation 7.7% -6.2%

DA Spinning -22.2% -23.5%

DA Supplemental -75.1% -42.4%

RT Regulation 14.0% 7.5%

RT Regulation Mileage ($/MW)

33.2% 29.8%

RT Spinning 9.6% -13.0%

RT Supplemental -54.9% -42.5%

Ancillary product prices in Summer 2018 were generally lower than those in

Summer 2018. Except for regulation mileage MCP which increased by 29.8% relative to last summer. This summer there were 31 intervals with reserve shortage, compared to 49 last summer. The lower number of reserve shortages drove the decrease in reserve product MCPs.

22

2. Price Convergence and Comparative Price Analysis

Figure V-2.1: DA and RT Hourly LMP Convergence for MISO: Summers of 2016, 2017, and 2018

27

.36

30

.72

30

.56

29

.00

30

.24

27

.38 32

.42

31

.30

30

.44

29

.55

28

.87

31

.39

27

.42

29

.73

30

.75

28

.13

31

.07

26

.83 31

.74

29

.33

31

.47

29

.30

28

.68

30

.85

5.93 6.91 6.25 5.84 6.76 4.52

8.665.25 5.71 6.36 5.71 6.54

-8

2

12

22

32

42

Ju

n -

16

Ju

l -

16

Aug -

16

Ju

n -

17

Ju

l -

17

Aug

- 1

7

Ju

n -

18

Ju

l -

18

Aug

- 1

8

Sum

me

r-1

6

Sum

me

r-1

7

Sum

me

r-1

8

$/M

Wh

Avg. DALMP Avg. RTLMP Avg. Difference (DA-RT) Absolute Avg. Diff.

Figure V-2.1 above shows that the hourly averages of both Day-Ahead and Real-Time prices during the 2018 summer, which were higher than those of summer 2017.

The average of monthly price differences this summer exhibited a Day-Ahead

price premium of $0.54/MWh, while last summer it was $0.20/MWh. The absolute average price difference increased by 14.6% relative to last summer, to $6.54/MWh.

Severe weather caused a local Transmission System Emergency in the South

Region on June 3rd. On June 4th MISO issued a Conservative Operations Alert and a Max Gen Alert. As a result Real Time LMPs in the South region spiked on June 3rd and 4th leading to a high DA-RT price deviation. Thus the absolute average price difference for June was $8.66/MWh, higher than the previous two Junes.

23

Figure V-2.2a: Scatter Plot of Average Daily DA and RT LMP Differences (North/Central): Summer 2018

-60

-50

-40

-30

-20

-10

0

10

20

3029-M

ay-1

8

03-J

un-1

8

08-J

un-1

8

13-J

un-1

8

18-J

un-1

8

23-J

un-1

8

28-J

un-1

8

03-J

ul-18

08-J

ul-18

13-J

ul-18

18-J

ul-18

23-J

ul-18

28-J

ul-18

02-A

ug-1

8

07-A

ug-1

8

12-A

ug-1

8

17-A

ug-1

8

22-A

ug-1

8

27-A

ug-1

8

01-S

ep-1

8

DA

LM

P m

inu

s R

T L

MP

( $

/MW

h)

ILL MICH MINN IND

95% quantile of MISO price difference for Summer 2018


Figure V-2.2a: Scatter Plot of Average Daily DA and RT LMP Differences (South): Summer 2018

-160

-110

-60

-10

40

29-M

ay-1

8

03-J

un-1

8

08-J

un-1

8

13-J

un-1

8

18-J

un-1

8

23-J

un-1

8

28-J

un-1

8

03-J

ul-18

08-J

ul-18

13-J

ul-18

18-J

ul-18

23-J

ul-18

28-J

ul-18

02-A

ug-1

8

07-A

ug-1

8

12-A

ug-1

8

17-A

ug-1

8

22-A

ug-1

8

27-A

ug-1

8

01-S

ep-1

8

DA

LM

P m

inu

s R

T L

MP

( $

/MW

h)

ARK LOU TEX MS



The scatter plots in Figures V-2.2a and V-2.2b above, based on statistical analysis, shows the daily average of hourly price differences between the Day-Ahead and Real-Time markets at the MISO Hubs during the 2018 summer.

24

Table V-2.1: Summary statistics for DA and RT LMP Differences at Hubs: Summer 2018

IND ILL MICH MINN ARK LOU TEX MS

Mean 1.09 1.26 0.77 0.34 0.95 -1.81 0.84 0.88

Std. Dev. 7.34 4.57 4.47 3.72 5.42 24.39 6.00 12.51

95% Quantile 8.64 7.80 8.32 6.42 8.31 16.26 8.35 21.86

5% Quantile -8.44 -6.38 -6.95 -6.47 -8.42 -19.28 -13.47 -20.37

Table V-2.1 contains additional statistics calculated from DA-RT LMP differences based on data over the three summer months of this 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, weather patterns, transmission constraint management practices, and the way RAC and Real-Time resource commitment processes are implemented.

For the North & Central region hubs most of the observations were clustered around the zero line, which shows a general convergence pattern. While for the South region hubs the price differences diverged more often. In particular price spikes at the Louisiana and Mississippi hubs were observed on a few days. As discussed above, the local Transmission System Emergency in the MISO South region led to Real-Time price spikes on June 3rd and 4th. On August 22nd high local congestion led to a significant Real-Time price spike at the Louisiana hub.

3. Real-Time Interface Prices at MISO, PJM and SPP

MISO continuously imports energy from and exports energy to external regions. This section analyzes the Real-Time interchange transactions among regions. These transactions may fulfill long-term or short-term bilateral contracts, or take advantage of short-term price differentials. An economic inefficiency occurs when the direction of energy flows is not consistent with price differentials. 3.1 Interface Prices at MISO and PJM

MISO’s imports and exports to PJM are scheduled in the MISO market at a single interface node -- MISO’s PJM Interface. Similarly, PJM’s imports and exports to MISO are scheduled in PJM’s market at a single interface node -- PJM’s MISO Interface. In this section (i) LMPs at both the MISO and PJM Interfaces (ii) the Economic Efficiency and the Revenue6 for the summers of 2016, 2017 and 2018 are analyzed.

6 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

25

Table V-3.1 below shows summary statistics for the Real-Time hourly LMPs at MISO’s PJM Interface and PJM’s MISO Interface. During the summer of 2018, the hourly average of MISO’s PJM Interface LMP was $28.93/MWh, while PJM’s MISO Interface LMP was $27.94/MWh; a difference of $0.99/MWh. Comparing with summer 2017, the interface prices for both RTOs were slightly higher, and the difference between the average interface prices increased.

Table V-3.1: Real-Time Hourly Interface Prices for the Summers of 2016, 2017, and 2018

Interface LMP

Summer Summer Summer Summer Summer Summer

2016 2017 2018 2016 2017 2018

MISO’s PJM Interface LMP $29.05 $27.50 $28.93 $17.76 $14.26 $ 14.58

PJM’s MISO Interface LMP $28.27 $27.11 $27.94 $16.65 $13.91 $ 13.16

Interface Price Difference

(MISO – PJM )$0.78 $0.38 $0.99 $16.78 $12.11 $ 13.50

Absolute Interface Price

Difference (MISO – PJM )$7.15 $5.31 $6.18 $15.20 $10.89 $ 12.04

Average Standard Deviation

On 6/1/2017 MISO changed its interface definition for PJM from the Old (~1800

nodes) to the New Common Interface (10 nodes). The new interface definition reduces the potential overlap in congestion component of pricing.

During the 2018 summer season, the standard deviation of hourly prices at

MISO’s PJM Interface increased slightly relative to Summer 2017, while at PJM’s MISO Interface it decreased slightly. This summer the absolute average of the price differences between the two interfaces increased to $6.18/MWh while last summer it was $5.31/MWh. Table V-3.2: Economic Inefficiency and Revenue for Summers of 2016, 2017, and 2018

Summer 2016

Summer 2017

Summer 2018

% of hours when flow is not consistent with the interface price differences (MISO – PJM )

38% 42% 39%

Economic Inefficiency (in millions) $16.20 $13.84 $8.79

Net Revenue from Real-Time Scheduling (in millions) $0.04 $2.55 $5.69

An economic inefficiency occurs when the direction of energy flow is not consistent with price differentials. The economic inefficiency for a particular hour is defined as the economic losses when the aggregate flow is from the RTO with the

26

higher interface price to the RTO with the lower interface price – estimated as the interface price difference multiplied by the MWh of flow. For the 2018 summer, the direction of energy flows was not consistent with price differentials in about 39% of all hours. The estimated value of Economic Inefficiency for Summer 2018 is $8.79 million, as shown in the table above.

As indicated in Table V-3.2 above, market participants collectively made money

in Real-Time scheduling at the PJM and MISO interfaces. Market participants earned revenues of $14.49 million in 1,355 hours and incurred losses of $8.79 million in 853 hours, yielding net revenues of $5.69 million.

3.2 Interface Prices at MISO and SPP

MISO’s imports and exports to SPP are scheduled in the MISO market at a single interface node -- MISO’s SWPP Interface. Similarly, SPP’s imports and exports to MISO are scheduled in SPP’s market at a single interface node -- SPP’s MISO Interface. In this section (i) LMPs at both the MISO and SPP Interfaces; (ii) the Economic Efficiency and the Revenue7 for the summer of 2018 is analyzed.

Table V-3.3 below shows summary statistics for the Real-Time hourly LMPs at MISO’s SPP Interface and SPP’s MISO Interface. During the summer of 2018, the hourly average of MISO’s SPP Interface LMP was $26.52/MWh, while the average of SPP’s MISO Interface LMP was $26.60/MWh; a difference of $0.08/MWh. Comparing with the summer of 2017, this summer the average price difference between the MISO and SPP interfaces decreased.

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

27

Table V-3.3: Real-Time Hourly Interface Prices for the Summers of 2016, 2017, and 2018

Interface LMP Average Standard Deviation

Summer Summer Summer Summer Summer Summer

2016 2017 2018 2016 2017 2018

MISO’s SPP Interface LMP

$25.46 $25.42 $26.52 $13.05 $13.27 $13.90

SPP’s MISO Interface LMP

$24.12 $24.90 $26.60 $13.62 $26.47 $20.39

Interface Price Difference (MISO – SPP )

$1.33 $0.52 -$0.08 $14.88 $26.46 $21.04

Absolute Interface Price Difference (MISO – SPP )

$6.35 $7.57 $8.65 $13.53 $25.36 $19.18

During the 2018 summer season, the standard deviation of hourly prices at

MISO’s SPP interface increased slightly, while at SPP’s MISO interface it decreased relative to Summer 2017.

For the 2018 summer, the direction of energy flows was not consistent with price differentials in about 72% of all hours. The estimated value of economic inefficiency for the 2018 summer is $6.17 million.

28

4. Virtual Transactions

Virtual transactions are purely financial positions that can be taken in the Day-Ahead energy market and do not have to be backed by physical generation or load.

The chart below illustrates MISO’s virtual supply and demand volumes in the summers of 2016, 2017 and 2018.

Figure V-4.1: Monthly Avg. of Cleared Virtual Load and Cleared Virtual Supply during the summers of 2016, 2017, and 2018.

-10000

-8000

-6000

-4000

-2000

0

2000

4000

6000

8000

10000

Jun

-16

Jul-

16

Au

g-1

6

Jun

-17

Jul-

17

Au

g-1

7

Jun

-18

Jul-

18

Au

g-1

8

Sum

me

r 2

01

6

Sum

me

r 2

01

7

Sum

me

r 2

01

8

MW

VLOAD VSUPPLY NET

Net is defined as the difference between Cleared Virtual Load and Cleared Virtual Supply.

During the 2018 summer, the volumes of cleared virtual demand and cleared virtual supply increased by 11.2% and 13.7%, respectively, relative to the 2017 summer. The net virtual load (the difference between cleared virtual load and cleared virtual supply) averaged -130 MW.

29

5. RSG

Figure V-5.1: MISO Market Wide RSG Make Whole Payments in Day-Ahead and Real-Time Markets - summers of 2016, 2017, and 2018

$3.13$2.24

$3.44 $3.34 $3.28 $2.67$2.02

$1.29$2.06

$6.43$9.00

$10.64

$4.10

$6.46

$5.31$7.74

$7.48

$7.68

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

Jun Jul Aug Jun Jul Aug Jun Jul Aug


$ M

illio

ns

Real-Time RSG MWP Day-Ahead RSG MWP

Figure V-5.1 shows Day-Ahead and Real-Time RSG uplifted to the market. The total Real-Time RSG this summer was about $22.9 million, an increase of 44.3% in comparison to last summer. While, Day-Ahead RSG decreased by 42.2% to about $5.4 million.

30

6. FTR

Table V-6.1: MISO FTR Funding and Shortfall


Millions

FTR Target Credit Alloc.

FTR Funding

Funding Percent


FTR Funding

Funding Percent


FTR Funding

Funding Percent

Jun $116 $116 100% $135 $135 100% $139 $139 100%

Jul $129 $129 100% $107 $107 100% $97 $97 100%

Aug $145 $145 100% $72 $72 100% $77 $77 100%

Total $390 $390 100% $314 $314 100% $312 $312 100% Values may change due to resettlement.

Table V-6.1 above shows the monthly FTR funding levels during Summers of

2016, 2017, and 2018.

miso 2018 summer assessment report market and operations … summer assessment... · 2018. 10....

Documents