November 2017 Monthly Market Assessment Report Monthly Report... · Peak hour Load2 and Real-Time Daily Integrated Peak Load hour Generation Dispatch target without Imports or Exports

November 2017 Monthly Market Assessment Report

January 11

th, 2018

Market Analysis and Quality Assessment

Table of Contents Publicly Available Sources ................................................................................................. 01

Disclaimer .......................................................................................................................... 02

Market Report: Market Focus ............................................................................................ 03

Summary ........................................................................................................................... 09

Section 1: Market Price Analyses ..................................................................................... 11

Section 2: Ancillary Services Market Analysis .................................................................. 18

Section 3: Price Duration Curves ...................................................................................... 27

Section 4: Load and Supply .............................................................................................. 29

Section 5: Virtual Activity .................................................................................................. 31

Section 6: FTR ................................................................................................................... 35

Section 7: Fuel Mix Section .............................................................................................. 37

Section 8: Wind Utilization ................................................................................................. 44

Section 9: Outage Information .......................................................................................... 46

Section 10: Cost and Dispute Summary ........................................................................... 48

Section 11: Ramp Capability Product Summary ............................................................... 50

Page 1

Publicly Available Sources PJM Market http://www.pjm.com NY ISO http://www.nyiso.com ISO-NE http://iso-ne.com Nominal and Real Coal Prices Price Data http://www.eia.doe.gov PPI Index http://data.bls.gov Natural Gas Prices Price Data http://www.theice.com PPI Index http://data.bls.gov Distillate Oil Prices Price Data http://www.eia.gov/forecasts/steo/tables/ PPI Index http://data.bls.gov

http://www.pjm.com/

http://www.nyiso.com/

http://iso-ne.com/

http://www.eia.doe.gov/

http://data.bls.gov/

http://www.theice.com/


http://www.eia.gov/forecasts/steo/tables/


Page 2

Disclaimer: THE DATA AND ANALYSIS IN THIS REPORT ARE PROVIDED FOR INFORMATIONAL PURPOSES ONLY AND SHALL NOT BE CONSIDERED OR RELIED UPON AS MARKET ADVICE OR MARKET SETTLEMENT DATA. MISO MAKES NO REPRESENTATIONS OR WARRANTIES OF ANY KIND, EXPRESS OR IMPLIED, WITH RESPECT TO THE ACCURACY OR ADEQUACY OF THE INFORMATION CONTAINED HEREIN. MISO SHALL HAVE NO LIABILITY TO RECIPIENTS OF THIS INFORMATION OR THIRD PARTIES FOR THE CONSEQUENCES ARISING FROM ERRORS OR DISCREPANCIES IN THIS INFORMATION, FOR RECIPIENTS' OR THIRD PARTIES' RELIANCE UPON SUCH INFORMATION, OR FOR ANY CLAIM, LOSS OR DAMAGE OF ANY KIND OR NATURE WHATSOEVER ARISING OUT OF OR IN CONNECTION WITH (i) THE DEFICIENCY OR INADEQUACY OF THIS INFORMATION FOR ANY PURPOSE, WHETHER OR NOT KNOWN OR DISCLOSED TO MISO, (ii) ANY ERROR OR DISCREPANCY IN THIS INFORMATION, (iii) THE USE OF THIS INFORMATION, OR (iv) ANY LOSS OF BUSINESS OR OTHER CONSEQUENTIAL LOSS OR DAMAGE WHETHER OR NOT RESULTING FROM ANY OF THE FOREGOING.

Page 3

Market Report: Market Focus

Market outcomes from previous time periods have not been adjusted for membership changes, unless otherwise noted. Caution should be used when making any comparisons.

Highlights: November temperatures were cooler relative to last year. As a result, average load was 71.6 GW, an increase of 3.6 GW relative to last November. Load peaked at 84 GW on Nov 6th, and was 2.5 GW higher than last November’s peak load. Energy prices averaged $27.30/MWh, around 10% higher than last November. Wind production set a new record of 14.6 GW on Nov 21st.

November Historical Highlights: System-Wide Average Monthly Price1 ($/MWh)

35.34

23.17 24.62 27.2734.34

23.11 24.80 27.25

1.00 0.06 -0.19 0.024.93 3.98 3.29 4.35

2014 2015 2016 2017

Day-Ahead Real-Time

Average (DA-RT) Difference Average Absolute (DA-RT) difference

November Historical Highlights: System-Wide Load2 (MW)

75,484 68,90867,988

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

2 ICCP Load data, figures may change due to availability.

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

Nov-14 Nov-15 Nov-16 Nov-17

average 36.71 48.21 48.79 43.62

Max 62.32 70.28 75.46 62.28

Min 15.01 22.62 26.50 23.64

Hours<30 211 31 17 21

Hours<20 18 0 0 0

Summary of Load-weighted Temperature

Page 4

Market Report: Market Focus, cont.

Figure 1: MISO Real-Time Daily Integrated Peak Load hour LMP1, Real-Time Daily Integrated Peak hour Load2 and Real-Time Daily Integrated Peak Load hour Generation Dispatch target without Imports or Exports

In general, price and load are expected to trend together, ceteris paribus.

Figure 2: MISO Real-Time Daily Hub Average LMP

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Page 5

Real-Time price trends indicate daily average market price fluctuations and movements.

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On November 4th the Louisiana hub experienced prices between $137.29 and $564.79/MWh during HE15 to HE17. This price spike was due to local congestion. Other contributing factors were outages and high load.

On November 6th the Texas hub had Real-Time price in the $149.09 to $397.57/MWh range from HE 14 to HE 18. The high prices were driven by generation and transmission outages which caused local congestion.

MISO monthly average RT LMP

Page 6


Figure 3: MISO Real-Time Daily Average Regulation Reserve Requirement, Regulation Reserve Cleared, and Regulation Reserve MCP

Figure 4: MISO-Wide Daily Averaged Day-Ahead and Real-Time Ancillary Services Market Clearing Prices

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Page 7


The thirteen month average (November 2016 – November 2017) of daily prices for both MISO and PJM were $28.53/MWh and $28.57/MWh, respectively. Figure 5: MISO1 and PJM daily averaged Real-Time LMP

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Figure 6: Compares the Real-Time Daily Integrated Peak hour load2 to: 1) the Mid-Term Load Forecast at that hour 2) the Day-Ahead committed capacity plus Forward RAC committed capacity plus Intraday RAC committed capacity plus Net Actual Interchange at that hour.

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Page 8

Market Report: Market Focus, cont. Figure 7: Trend of Total Real-Time Imports and Exports at MISO. * Values may change due to settlement.

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Average Exports from Jan 2016 - Dec 2016Average Imports from Jan 2016 - Dec 2016

Page 9

Summary:

1) MISO’s reliability, markets and operational functions performed well in November 2017.

2) This month the footprint experienced temperatures more consistent with winter weather.

i. Heating Degree Days increased compared to last November. As such, average load this November was 72 GW, compared to 68 GW last November.

ii. The monthly instantaneous peak load of 84.5 GW occurred on November 6th.

3) System-wide energy1 prices increased relative to last November.

i. Energy prices averaged $27.30/MWh, 10% higher than last November.

ii. Natural gas prices averaged $3/MMBtu, 22% higher than last November.

4) Planned generator outages fell from 29.3 GW last month to 20.5 GW this month. Forced generator outages fell from 20.8 GW to 18.6 GW.

5) November total wind energy production in MISO was 5,072 GWh down from October’s 5,387 GWh.

i. This month wind production accounted for 10.8% of MISO’s total energy, the same as last November.

ii. MISO set a new all-time peak wind output of 14.6 GW on November 21st, largely driven by increased installed capacity in 2017.

iii. November hourly wind generation exceeded 9 GW in 227 hours, while last November it was 195 hours.

6) This month, total Real-Time RSG Make Whole Payment (MWP) was $3.7 Million, while last month it was $6.5 Million. This month total Day-Ahead RSG MWP was $1.9 Million, while last month it was $4.0 Million.

i. The portion of Real-Time RSG MWP associated with constraint mitigation increased from 19.1% in October 2017 to 26.5% in November 2017.

ii. The portion of DA RSG MWP associated with VLR commitments decreased from 66.0% last month to 37.6% this month.

7) The FTR Funding factor was 100% for November 2017.

8) MISO Transmission Expansion Plan (MTEP): On December 7, 2017, the MISO board of directors approved the 2017 MTEP representing an investment of $2.6 billion aimed at improving energy access and reliability. The plan includes five interregional Targeted Market Efficiency Projects (TMEP) approved in partnership with PJM.

9) NERC Grid Ex: MISO participated in a NERC conducted voluntary security exercise, GridEx IV, from November 15th – 16th. Participants were provided with an opportunity to exercise their response to a simulated large-scale cyber/physical attack on electric and other critical infrastructures across North America.

10) Energy Offer Cap: FERC rejected MISO’s compliance filing for Order 831 (Energy Offer Cap Revision). Similar to the previous three years, MISO has filed a waiver for the upcoming winter season that will allow resources to recover verifiable incremental energy costs in excess of the $1,000/MWh offer cap, in the event their fuel costs rise to high levels.

Page 10

Section 1: Market Price1 Analyses

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ILL IND MICH MINN ARK LOU TEX MISO

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Monthly Average Peak and Off-Peak Hub and System-wide LMPs

DA_Peak RT_Peak DA_OffPeak RT_OffPeak

The chart above shows the monthly average Peak and Off-Peak hub and system-wide1

LMPs.

Again this month, the Texas hub had the highest average Real-Time Peak LMP of all the hubs. The average Real-Time LMP at this hub was $35.00/MWh compared with last month’s $31.71/MWh.

Average System-wide1 Day-Ahead and Real-Time LMPs1 were both $27.27/MWh this

month. Average Day-Ahead and Real-Time prices decreased compared to last month, from $27.78/MWh and $26.68/MWh respectively.

The highest daily MISO system-wide1 average Day-Ahead LMP of $48.47/MWh occurred

on November 7th HE 19. The highest daily MISO system-wide average Real-Time LMP of $163.62/MWh occurred on November 4th HE 16. This Real Time price spike was impacted by local congestion. Other contributing factors were forced outages and high load.

Page 11

Section 1: Market Price1 Analyses, cont.

For illustrative purposes, prices at the Indiana, Minnesota, Michigan and Louisiana hubs were selected for trend analysis, as shown in the following two graphs.

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IND_DA LOUIS_DA MINN_DA MISO_DA MICH_DA

Mean minus Standard Deviation of MISO Day-Ahead LMP for the last 13 months

Mean plus Standard Deviation of MISO Day-Ahead LMP for the last 13 months

Mean minus Standard Deviation of MISO Day-Ahead LMP for the last 13 months

Mean plus Standard Deviation of MISO Day-Ahead LMP for the last 13 months

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Mean minus Standard Deviation of MISO Real-Time LMP for the last 13 months

Page 12

1.1 Price Volatility

Volatility is measured in terms of standard deviation, which shows how much variation or dispersion there is from the “average” or an expected value. A low standard deviation indicates that the data points tend to be very close to the mean, whereas high standard deviation indicates that the data is spread out over a large range of values.

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ARK IND ILL LOU MICH MINN TEX MISO

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Page 13

1.1 Price Volatility, con’t

The discussion below summarizes the Day-Ahead and Real-Time price differences this month.

Average absolute value of DA-RT hourly price differences: This month, the MISO system-wide average of the absolute value of the DA-RT price1 difference for peak periods was $6.23/MWh in November, nearly the same as October’s $6.25/MWh. In the off-peak hours the difference fell from $2.92/MWh last month to $2.71/MWh this month.

The average of absolute LMP1 difference between the Day-Ahead and Real-Time markets expressed as a percentage of the average Day-Ahead LMP1 was 16.0% for this month.

Hub with the narrowest DA-RT hourly price differences: For the peak period, the hub with the narrowest DA-RT average price difference was the Arkansas hub with an average difference of $0.14/MWh and an associated standard deviation of $10.54/MWh. For the off-peak period, the hubs with the narrowest average price difference was the Indiana hub, which had an average DA-RT price difference of $0.29/MWh and an associated standard deviation of $4.66/MWh.

Hub with the widest DA-RT hourly price differences: For the peak period, the hub with the widest DA-RT average price difference was the Minnesota hub with an average difference of $1.71/MWh and an associated standard deviation of $10.08/MWh. For the off-peak period, the hub with the widest DA-RT average price difference was the Louisiana hub with an average difference of $-2.71/MWh and associated standard deviation of $30.32/MWh.

Page 14

1.1 Price Volatility, con’t

The graphical analysis below shows the trend analysis of average monthly price differences (DA-RT) at the Illinois, Minnesota and Louisiana Hubs relative to MISO system-wide1 average price difference.

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Monthly Average of Hourly Day-Ahead LMP Minus Hourly Real-Time LMP

November 2016 - November 2017

MINN ILL LOU MISO

The average MISO system-wide energy price1 difference between the Day-Ahead and

Real-Time markets was $0.02/MWh (i.e., Day-Ahead price premium) this month. Last month, the system-wide price1 difference was $1.10/MWh (i.e., Day-Ahead price premium). For last November, the MISO system-wide price1 difference was $-0.19/MWh (i.e., Real-Time price premium).

Page 15

1.2 Statistical Price Convergence Analysis

The scatter diagrams below illustrate the daily average of the hourly price differences between Day-Ahead and Real-Time markets at the MISO Hubs. When most of the observations are clustered around the zero line, a convergence pattern is suggested.

Tables inserted within the scatter diagrams contain price correlation and additional statistics calculated from the DA-RT LMP differences. The Quantile Range (95%, 5%), based on price data over the last thirteen months, and standard deviations provide statistical estimates of price volatility reference levels over the given period. 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 RT resource commitment processes are implemented.

The data points outside the statistical reference bands indicate relative price divergence between the Day-Ahead and Real-Time markets at the respective hubs. For illustration purposes, the prices of the Indiana hub, the Minnesota hub, the Arkansas hub and the Louisiana hub were selected for analysis, as shown in the following two graphs.

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Daily Average of Hourly DA LMP Minus Hourly RT LMP Over

Peak Hours November 2017

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95th percentile of MISO price

5th percentile of MISO price

Weekends and Holidays are considered Off-Peak

ARK IND LOU MINN

0.2344 0.2924 0.2491 0.5858

Correlation between DA and RT LMPs in Peak hours in November 2017

ARK IND LOU MINN

Mean $0.46 -$0.32 -$1.65 $0.28

StdDev $7.44 $11.99 $33.73 $6.64

95% Quantile $9.83 $11.02 $14.28 $9.04

5% Quantile -$9.18 -$14.27 -$27.98 -$11.61

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95th percentile of MISO price difference for Jan 2016- Dec 2016

5th percentile of MISO price difference for Jan 2016 - Dec 2016

The correlation coefficients between the Day-Ahead and Real-Time energy component of

LMPs were 0.44 and 0.56 for the peak and off-peak periods this month, respectively. Last month the correlation coefficients were 0.44 and 0.71, respectively.

ARK IND LOU MINN

0.6287 0.6474 0.3441 0.7472

Correlation between DA and RT LMPs in Off-Peak hours in November 2017

ARK IND LOU MINN

Mean $0.34 $0.05 $0.21 $0.03

StdDev $3.58 $3.20 $8.95 $3.90

95% Quantile $5.52 $4.19 $6.68 $6.30

5% Quantile -$4.29 -$5.09 -$5.66 -$5.28

Page 17

1.3 Energy Price to Natural Gas Price Correlation Analysis

The chart below shows the trend and correlation analysis of the monthly Average MISO

System-wide1 Day-Ahead and Real-Time LMPs to the nominal monthly average of natural gas fuel prices at the Chicago Citygate and Henry hubs.

This month the average system-wide Day-Ahead LMP was $27.27/MWh, $2.65/MWh

more than last November. The average Henry Hub and Chicago Citygate natural gas prices increased by 21.0% and 23.9%, respectively, compared with November 2016.

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Monthly Average of DA LMP, RT LMP and Natural Gas PricesNovember 2016 - November 2017

MISO DA LMP MISO RT LMP Chicago Citygate Nominal Henry Hub Nominal

Correlation Matrix

MISO DA LMP MISO RT LMP Henry Hub Nominal Chicago Citygate Nominal

MISO DA LMP 1

MISO RT LMP 0.931 1

Henry Hub Nominal 0.637 0.481 1

Chicago Citygate Nominal 0.589 0.483 0.962 1

Page 18

Section 2: Ancillary Services Market Analysis MISO establishes Reserve Zones to ensure Regulating Reserves and Contingency Reserves are dispersed in a manner that prevents adverse operating conditions affecting the reliability of the Transmission System. The map below shows the various zones that are in MISO. The definition of the Reserve Zones is updated on a quarterly basis, in conjunction with the update of the Network Model.

Page 19

2.1 Market Clearing Price Trend

The Ancillary Services Market started in January 2009. On December 17th, 2012 MISO began Frequency Regulation Compensation (FERC Order 755) in order to compensate frequency regulation resources on the actual regulation service provided. In the Real-Time market, Regulation market clearing prices are divided into a regulating capacity MCP and a regulating mileage MCP. Resources will be paid or charged regulation payments based on regulation mileage performance and derived from Regulation Mileage MCP. The next two charts show the trend of the monthly average Day-Ahead and Real-Time Market Clearing Prices.

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Monthly Average of the MISO Wide Day-Ahead Market Clearing Prices

Regulation Spinning Supplemental

$/M

Wh

8.8

4

10.4

6

9.6

6

8.2

5

9.7

8

10.4

3 12.2

6

9.3

3 10.7

4

8.0

6

11.7

0

9.5

1

8.9

3

0.5

2

0.6

4

0.5

5

0.5

3

0.5

1

0.5

0

0.5

8

0.4

5

0.3

9

0.3

4

0.6

1

0.4

2

0.4

4

1.9

8

2.0

5

2.2

9

1.6

5 2.6

0 4.0

0 4.8

5

2.5

9 3.8

4

2.7

3

2.9

9

3.1

9

2.4

8

0.6

0

1.0

3

0.9

1

0.2

5 1.2

1

1.6

2 3.0

7

0.7

7 2.1

2

0.6

8

1.0

2

0.7

8

0.4

1

0

5

10

15


Monthly Average of the MISO Wide Real-Time Market Clearing Prices

Regulation Regulation Mileage Spinning Supplemental

$/M

Wh

Page 20

2.2 Market Clearing Price Analysis

The table below shows hourly summary statistics of price dispersion characteristics for MISO-wide ancillary product prices, as presented in the previous charts.

MISO Wide hourly price summary statistics for the month: ($ per MWh (Regulation Mileage is $/MW))

Type Maximum Average Minimum

Standard

Deviation

Coefficient of

Variation (CV)

REG_DA_MCP $24.62 $10.09 $2.98 $3.60 35.7%

SPIN_DA_MCP $11.61 $2.70 $0.50 $2.00 73.8%

SUPP_DA_MCP $0.50 $0.42 $0.22 $0.07 16.7%

REG_RT_MCP $88.66 $8.93 $2.50 $5.86 65.6%

REG_RT_MILEAGE_MCP $2.68 $0.44 $0.09 $0.29 64.6%

SPIN_RT_MCP $81.01 $2.48 $0.11 $4.30 173.2%

SUPP_RT_MCP $48.47 $0.41 $0.11 $2.22 540.1% * Hourly minimum and maximum for MISO wide average MCP For November 2017, the average Day-Ahead and Real-Time Ancillary Services product prices were lower than those seen last month.

On average, Regulation resources passed the hourly mileage performance test 82.58%†

of the time this month. For comparison, Regulation resources passed the hourly mileage performance test roughly 81.30%† last month.

Average Real-Time Regulation Mileage MCP for this month was $0.44/MW, while last month it was $0.76/MW. The Regulation Mileage Deployment Ratio for the month of December 2017 is 0.71129983.

† Values may change due to resettlement.

Page 21

2.2.1 Daily Averages of Day-Ahead and Real-Time Regulation Reserve MCP Differences

-5

0

5

10

15

20

25

11/1

11/2

11/3

11/4

11/5

11/6

11/7

11/8

11/9

11/1

0

11/1

1

11/1

2

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/1

8

11/1

9

11/2

0

11/2

1

11/2

2

11/2

3

11/2

4

11/2

5

11/2

6

11/2

7

11/2

8

11/2

9

11/3

0

$/M

Wh

Daily Average of MISO Wide Regulation Reserve MCP Difference

November 2017

DA_Reg_MCP_minus_RT_Reg_MCP

Page 22

2.2.2 Daily Averages of Spinning and Supplemental Reserve MCPs

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

11/1

11/2

11/3

11/4

11/5

11/6

11/7

11/8

11/9

11/1

0

11/1

1

11/1

2

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/1

8

11/1

9

11/2

0

11/2

1

11/2

2

11/2

3

11/2

4

11/2

5

11/2

6

11/2

7

11/2

8

11/2

9

11/3

0

$/M

Wh

Daily Average of the MISO Wide Spinning Reserve MCPs

November 2017

Spin_DA_MCP SPIN_RT_MCP

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11/1

11/2

11/3

11/4

11/5

11/6

11/7

11/8

11/9

11/1

0

11/1

1

11/1

2

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/1

8

11/1

9

11/2

0

11/2

1

11/2

2

11/2

3

11/2

4

11/2

5

11/2

6

11/2

7

11/2

8

11/2

9

11/3

0

$/M

Wh

Daily Average of the MISO Wide Supplemental Reserve MCPs

November 2017

SUPP_DA_MCP SUPP_RT_MCP

Page 23

2.2.3 Hourly Average of Ancillary Service Product MCPs by Zones

On November* 1st, 2011, MISO implemented the Enhanced Reserve Procurement Procedures to ensure deliverability of Ancillary Services Market products. The Day Ahead and Real Time markets solve co-optimized reserve zone requirements to meet system deliverability requirements on a zonal basis. Reserve procurement adds the potential for price differences across zones due to transmission constraints.

This change included enhanced offline Reserve Zone Requirements studies. Since the implementation of the Enhanced Reserve Procurement Procedures, inter-zonal congestion has reduced and Real-Time zonal MCP separation across the zones has decreased.

10.0

9

10.0

9

10.0

9

10.0

9

10.0

9

10.0

9

10.0

9

10.0

9

10.0

9

8.9

3

8.9

3

8.9

3

8.9

3

8.9

3

8.9

3

8.9

7

8.9

3

8.9

3

2.7

0

2.7

0

2.7

0

2.7

0

2.7

0

2.7

0

2.7

0

2.7

0

2.7

0

2.4

8

2.4

8

2.4

8

2.4

8

2.4

8

2.4

8

2.5

5

2.4

7

2.4

8

0.4

2

0.4

2

0.4

2

0.4

2

0.4

2

0.4

2

0.4

2

0.4

2

0.4

2

0.4

1

0.4

1

0.4

1

0.4

1

0.4

1

0.4

1

0.4

4

0.4

0

0.4

1MISO Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7 Zone 8

$/M

Wh

Day-Ahead and Real-Time Monthly Average of Hourly MCPs by Zones

November 2017

REG_DA_MCP REG_RT_MCP SPIN_DA_MCP SPIN_RT_MCP SUPP_DA_MCP SUPP_RT_MCP

Page 24

2.3 Market Reserve Requirement and Cleared Regulation: Real-Time market wide Regulation Reserve shortages were observed for a total of 3 intervals (0.03%)* in November 2017 on 3 days (10.0%)**. In comparison, Real-Time market wide Regulation Reserve shortages were observed for a total of 4 intervals (0.03%)* in October 2017 on 3 days (9.7%)**.

300

320

340

360

380

400

420

440

11/1

11/2

11/3

11/4

11/5

11/6

11/7

11/8

11/9

11/1

0

11/1

1

11/1

2

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/1

8

11/1

9

11/2

0

11/2

1

11/2

2

11/2

3

11/2

4

11/2

5

11/2

6

11/2

7

11/2

8

11/2

9

11/3

0

MW

MISO Wide Real-Time Daily Average Regulation Reserve Requirement and Cleared

November 2017

Regulation Reserve Requirement Regulation Reserve Cleared

A Regulation Reserve shortage occurred in these 5-minute intervals:

o November 1st: 10:15 am (94.0 MW deficit) o November 7th: 12:40 pm (307.6 MW deficit) o November 26th: 5:50 pm (190.7 MW deficit)

* Scarcity intervals as a percentage of total monthly intervals. **Days with Scarcity observations as a percentage of total days in the month.

Page 25

2.3 Market Reserve Requirement and Cleared, con’t Spinning: Real-Time market wide Spinning Reserve shortages were observed for a total of 12 intervals (0.14%)* in November 2017 on 6 days (20.0%)**. In comparison, Real-Time market wide Spinning Reserve shortages were observed for a total of 19 intervals (0.21%)* in October 2017 on 9 days (29.0%)**.

800

850

900

950

1000

1050

1100

11/1

11/2

11/3

11/4

11/5

11/6

11/7

11/8

11/9

11/1

0

11/1

1

11/1

2

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/1

8

11/1

9

11/2

0

11/2

1

11/2

2

11/2

3

11/2

4

11/2

5

11/2

6

11/2

7

11/2

8

11/2

9

11/3

0

MW

MISO Wide Real-Time Daily Average Spinning Reserve Requirement and Cleared

November 2017

Spinning Reserve Requirement Spinning Reserve Cleared

A Spinning Reserve shortage occurred in these 5-minute intervals:

o November 1st: 10:15 am (492.6 MW deficit), 10:20 am (287.9 MW deficit), 10:25 am (58.1 MW deficit), 4:20 pm (148.6 MW deficit)

o November 2nd: 3:25 pm (195.1 MW deficit), 5:45 pm (47.4 MW deficit) o November 4th: 6:50 pm (73.4 MW deficit) o November 7th: 12:40pm (697.5 MW deficit) o November 11th: 9:10 am (211.2 MW deficit), 9:15 am (221.8 MW deficit) o November 26th: 5:50 pm (537.2 MW deficit), 5:55 pm (120.3 MW deficit)

Page 26

2.3 Market Reserve Requirement and Cleared, con’t Supplemental: Real-Time Supplemental Reserve shortages were observed for 2 intervals (0.02%)* in November 2017 on 1 days (3.30%)**. In comparison, Real-Time Supplemental Reserve shortages were observed for 3 intervals (0.03%)* in October 2017 on 2 days (6.67%)**.

800

900

1000

1100

1200

1300

1400

11/1

11/2

11/3

11/4

11/5

11/6

11/7

11/8

11/9

11/1

0

11/1

1

11/1

2

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/1

8

11/1

9

11/2

0

11/2

1

11/2

2

11/2

3

11/2

4

11/2

5

11/2

6

11/2

7

11/2

8

11/2

9

11/3

0

MW

MISO Wide Day-Ahead and Real-Time Daily Average Supplemental Reserve Requirement and Cleared

November 2017

DA Supplemental Reserve Cleared RT Supplemental Reserve Cleared

A Supplemental Reserve shortage occurred in these 5-minute intervals:

o November 1st: 10:15 am (251.0 MW deficit), 10:20 am (46.3 MW deficit)

Page 27

Section 3: Price Duration Curves Price duration curves indicate the number of hours during the month that LMPs exceed a given level. The charts below contain LMP duration curves for each of the MISO Hubs.

3.1 Day-Ahead LMP Duration Curves

0

10

20

30

40

50

60

70

80

90

100

0

40

80

120

160

200

240

280

320

360

400

440

480

520

560

600

640

680

720

760

$/M

Wh

Number of Hours

Day-Ahead Price Duration of MISO Hubs

This month no Day-Ahead prices exceeded $100/MWh. Only Louisiana had any hours

exceeding $80.00/MWh There were no hubs with hours with negative prices.

Indiana Hub 0 (0.00%) 0 (0.00%) 693 (96.25%) 0 (0.00%)

Illinois Hub 0 (0.00%) 0 (0.00%) 715 (99.31%) 0 (0.00%)

Michigan Hub 0 (0.00%) 0 (0.00%) 692 (96.11%) 0 (0.00%)

Minnesota Hub 0 (0.00%) 0 (0.00%) 694 (96.39%) 0 (0.00%)

Arkansas Hub 0 (0.00%) 0 (0.00%) 718 (99.72%) 0 (0.00%)

Louisiana Hub 0 (0.00%) 1 (0.14%) 665 (92.36%) 0 (0.00%)

Texas Hub 0 (0.00%) 0 (0.00%) 682 (94.72%) 0 (0.00%)

Hours with

LMP > $100/MWh

Hours with

LMP > $80/MWh

Hours with

LMP < $40/MWh

Hours with

LMP < $0/MWh

Page 28

3.2 Real-Time LMP Duration Curves

-100

0

100

200

300

400

500

600

0

40

80

120

160

200

240

280

320

360

400

440

480

520

560

600

640

680

720

760

$/M

Wh

Number of Hours

Real-Time Price Duration of MISO Hubs

The Michigan, Arkansas, Louisiana and Texas hubs all had some hours with the LMP above

$150/MWh. The relatively flat segment of the curves suggests stable prices across hubs for most of the

month. Real-Time prices were negative at Illinois hub for 3 hours and at Minnesota hub for 5 hours.

Hours with

LMP > $150/MWh

Hours with

LMP > $100/MWh

Hours with

LMP < $50/MWh

Hours with

LMP < 0$/MWh

Indiana Hub 0 (0.00%) 1 (0.14%) 698 (96.94%) 0 (0.00%)

Illinois Hub 0 (0.00%) 1 (0.14%) 707 (98.19%) 3 (0.42%)

Michigan Hub 2 (0.28%) 5 (0.69%) 691 (95.97%) 0 (0.00%)

Minnesota Hub 0 (0.00%) 2 (0.28%) 705 (97.92%) 5 (0.69%)

Arkansas Hub 1 (0.14%) 3 (0.42%) 707 (98.19%) 0 (0.00%)

Louisiana Hub 4 (0.56%) 7 (0.97%) 691 (95.97%) 0 (0.00%)

Texas Hub 6 (0.83%) 9 (1.25%) 685 (95.14%) 0 (0.00%)

Page 29

Section 4: Load and Supply

The Load Duration Curves below indicate the number of hours during the month that load within the MISO market footprint was greater than a given level. Load Duration Curves show the comparative load* characteristics over time.

40

45

50

55

60

65

70

75

80

85

90

95

0

10

0

20

0

30

0

40

0

50

0

60

0

70

0

80

0

GW

Number of Hours

*

ICCP load data.

November temperatures were colder than last year for the MISO footprint. Average load this month was 72 GW, compared to 70 GW in October. The instantaneous load peaked at 84.5 GW on November 6th at hour ending 19.

Regionally, load averaged 37.0 GW, 16.7 GW and 17.8 GW in the Central, North and South Regions respectively. Compared to last month the average load increased in the Central and North regions while it decreased in the South region.

November-17 0(0.00%) 0(0.00%) 55(7.64%) 696(96.67%)

October-17 0(0.00%) 0(0.00%) 74(9.95%) 639(85.89%)

November-16 0(0.00%) 0(0.00%) 14(1.94%) 596(82.78%)

Hours with

Load >110GW

Hours with

Load >100GW

Hours with

Load >80GW

Hours with

Load >60GW

Page 30

4.1 Day-Ahead Physical Load and Supply Trend

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000


MW

h

Trend of Physical Load and Supply in Day Ahead Market

Period: Novmber 2016 - November 2017Physical Load Physical Supply

* Excluding imports and exports

November 2017 Physical Volume* in the Day-Ahead Market:

Traded 49,409,900 MWh for a value of $1,368,538,746. Traded 47,864,178 MWh for a value of $1,324,992,125.

Previous Month Physical Volume* in Day-Ahead Market:

Traded 50,589,585 MWh for a value of $1,436,107,565 for load. Traded 48,182,204 MWh for a value of $1,373,040,785 for supply.

Page 31

Section 5: Virtual Activity

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 charts below illustrate MISO’s cleared virtual supply and demand volumes.

When compared with last month, offered virtual load increased 3.2% and offered virtual

supply decreased 5.0%, while cleared virtual load decreased by 2.6% and cleared virtual supply decreased 9.3%. Relative to November 2016 offered virtual load increased 29.0% and offered virtual supply increased 0.9%, while cleared virtual load increased 34.5% and cleared virtual supply increased 12.7%.

The amount of offered virtual load and supply that MISO cleared this month was 24.3% and 23.5%, respectively.

5.1 Virtual Activity Trend

-1,000,000

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000


Virtual Load Cleared Virtual Supply Cleared Net Virtuals

Trends in Cleared Virtual Load and Virtual Supply in the Day-Ahead MarketPeriod: November 2016 - November 2017

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

The difference between cleared virtual load and cleared virtual supply (Net Virtual) is 205,132 MWh this month.

Page 32

5.1.1 Virtual Value

November 2017: Previous Month:

Load Traded 5,550,795 MWh for a value of $149,491,948

Traded 5,700,297 MWh for a value of $152,961,806

Supply Traded 5,345,663 MWh for a value of $137,014,394

Traded 4,758,230 MWh for a value of $147,656,486

5.2 Virtual Activity over Peak Hours The daily average of net virtual positions for the Peak hours oscillated between -860 MW

and 3,806 MW. Over the Peak hours, cleared virtual supply surpassed cleared virtual load on 3 days this month.

-12,000

-10,000

-8,000

-6,000

-4,000

-2,000

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

11/1

11/2

11/3

11/6

11/7

11/8

11/9

11/1

0

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/2

0

11/2

1

11/2

2

11/2

4

11/2

7

11/2

8

11/2

9

11/3

0

MW

Daily Average of Cleared Virtual Load and Virtual Supply over Peak hours

Period: November 2017

Virtual Supply Cleared Virtual Load Cleared Net Virtuals

Weekends and holidays are considered Off-Peak


Page 33

5.3 Virtual Activity over Off-Peak Hours The daily average net virtual positions during Off-Peak hours oscillated between -1,917 MW

and 1463 MW. Over the Off-Peak hours, cleared virtual supply surpassed cleared virtual load on 16 days this month.

-12,000

-10,000

-8,000

-6,000

-4,000

-2,000

0

2,000

4,000

6,000

8,000

10,000

12,000

11/1

11/2

11/3

11/4

11/5

11/6

11/7

11/8

11/9

11/1

0

11/1

1

11/1

2

11/1

3

11/1

4

11/1

5

11/1

6

11/1

7

11/1

8

11/1

9

11/2

0

11/2

1

11/2

2

11/2

3

11/2

4

11/2

5

11/2

6

11/2

7

11/2

8

11/2

9

11/3

0

MW

Daily Average of Cleared Virtual Load and Virtual Supply

over Off-Peak hours

Period: November 2017

Virtual Load Cleared Virtual Supply Cleared Net_Virtuals

Weekends and holidays are considered Off-Peak


Page 34

5.4 Virtual Profitability

0.86

0.180.47

1.02 1.03 1.03 1.140.87 0.78 0.67 1.28

0.59 0.73

$5

$4

$3

$2

$1

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

No

v-1

6

Dec

-16

Ja

n-1

7

Feb

-17

Mar-

17

Ap

r-1

7

May-1

7

Ju

n-1

7

Ju

l-17

Au

g-1

7

Sep

-17

Oct-

17

No

v-1

7

Ind

ex (

$/M

Wh

)

MISO Cleared Virtual Market Profit Index*

Decrement Increment Market Threshhold Upper Limit STD Lower Limit STD

Threshold - Daily Average STD = -1.17Virtual Profitability Determined by:-Hedging-LMP Variation between DA & RT

Threshold + Daily Average STD = 2.44

• Threshold is the average of monthly indices from January 2016- January 2017

• Daily Average STD is from November 2016 - November 2017

• Mo. StdDev is the standard deviation of daily cleared indices in the month

Threshold of $0.63/MWh

This month, the virtual profitability index4 was $0.73/MWh.

4 The virtual profitability market index is defined as the sum of profits/losses for all cleared virtual transactions divided by the volume (MWh) of

total cleared transactions. Virtual profits/losses are calculated by multiplying the cleared virtual MW and the imbalance between RT LMP and DA LMP for a cpnode, then summed across all cpnodes, all hours.

Mo. StDev 0.87 1.13 0.74 3.77 1.70 1.48 1.53 1.54 1.59 2.79 2.14 1.02 1.09

Page 35

Section 6: FTR

FTR Monthly and YTD Funding Allocation

The monthly FTR funding factor for November was 100.0%. − The total Day-Ahead Excess Congestion Fund5 for the month of November 2017 was

$5,373,545.28 which was higher than last month’s total of $3,041,313.77.

5 Data can change due to resettlement.

107.6

5

153.7

7

107.2

6

90.2

2

157.9

3

152.3

5

190.4

7

134.6

3

107.1

8

71.8

7

184.9

3

162.6

6

115.2

7

0.51

0.68

2.89

0.00

0.00 0.00

0.06

0.00

0.00

0.00

0.00

6.11

0.00

-$50

$0

$50

$100

$150

$200

$250


$ i

n M

illi

on

s

FTR Funding C

Monthly Funding for Credits Net Shortfall


Monthly FTR Allocation (%) 99.5% 99.6% 97.4% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 96.4% 100.0%

YTD FTR Allocation (%) 100.0% 100.0% N/A N/A N/A 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Page 36

November 2017 Transmission Binding Constraints

The binding transmission constraints that have contributed more than $500,000 of FTR

Shortfall are listed above, sorted by the level of FTR Shortfall. For each binding transmission constraint, the table provides the constraint name, the contingency name, whether the constraint is Market to Market constraint, the amount of FTR Shortfall, and a short description of the cause.

Constraint Contingency M2M?Monthly Shortfall by

ConstraintNotes

NSES-RAM452 FLO BLACKBERRY-NEOSHO AECWR02

Y

($5,852,480)

Congestion was modelled in the FTR Market but at a higher limit

relative to Day Ahead

NELSON_E T2 FLO ROSE BLUFF-PPF EE23131

N

($1,256,175)

WLDW-MCML FLO ARP-RCKRN+POE+COC+TBWF+SPS ALEWPS4G

N

($744,087)

DELHI_E-TALULA FLO BAXTR WILSN-PERRYV EE50136

N

($619,012)

HARTBG AT2 FLO HARTBURG-NELSON EE50130

N

($823,468)

The exact constraint was not modelled in the FTR market

Page 37

Section 7: Fuel Mix Section

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%. *On June 1, 2011, MISO successfully launched Dispatchable Intermittent Resources (DIRs), allowing participation in the Real-Time energy market. ^^Gas excludes Combined Cycle units.

48.1

%

83.2

%

35.0

%

1.9

%

0.0

%

1.6

%

30.6

%

60.9

%

91.1

%

54.7

%

1.4

%

0.1

% 4.6

%

41.8

%

54.1

%

86.9

%

44.2

%

1.7

%

0.0

%

3.0

%

35.8

%

0%

20%

40%

60%

80%

100%

CC Coal Gas Nuclear Oil Hydro Wind

% o

f T

ime

Fuel

Percentage of Time a Fuel is at the Margin in Real-Time

Period : November 2017

Off-Peak On-Peak Total

Nov-17 Oct-17 Change Nov-17 Nov-17 Change Nov-17 Oct-17 Change

CC 48.1% 44.2% 3.9% 60.9% 47.7% 13.2% 54.1% 45.8% 8.2%

Coal 83.2% 80.3% 3.0% 91.1% 79.9% 11.2% 86.9% 80.1% 6.8%

Gas 35.0% 43.6% -8.6% 54.7% 63.4% -8.8% 44.2% 53.0% -8.8%

Nuclear 1.9% 1.0% 0.9% 1.4% 0.2% 1.2% 1.7% 0.6% 1.0%

Oil 0.0% 0.0% 0.0% 0.1% 1.1% -1.1% 0.0% 0.5% -0.5%

Hydro 1.6% 0.8% 0.8% 4.6% 2.6% 2.0% 3.0% 1.7% 1.3%

Wind 30.6% 59.8% -29.2% 41.8% 43.4% -1.5% 35.8% 52.0% -16.2%

FuelOff-Peak On-Peak Total

Page 38

7.1 Real -Time Generation by Fuel Type++

Battery, 0.0%

Coal, 49.3%

Coal/Gas, 0.2%

Coal/Oil, 0.1%

Gas, 17.7%

Nuclear, 16.3%

Oil, 0.0%

Oil/Gas, 2.9%

Other, 0.2%

Pet Coke, 1.2%Solar,

0.0%Waste, 0.3%

Water, 1.0%

Wind, 10.8%

Percent Real-Time Dispatched Generation^^ by Fuel Type++

November 2017

The sum of hourly integrated Real-Time generation** in November 2017 was 47,792 GWh,

which was a decrease of 367 GWh from October 2017. ^^Based on 5-minute unit level committed generation dispatch target **Hourly Committed Generation Dispatch Target; imports excluded. ++Based on Asset Registration Fuel Type designation; combined cycle units not excluded from gas fuel type.

Nov-17 Oct-17 Change

Coal 49.3% 45.4% 3.9%

Gas 17.7% 21.2% -3.5%

Hydro 1.0% 1.0% 0.0%

Nuclear 16.3% 17.0% -0.8%

Oil/Gas 2.9% 2.7% 0.3%

Wind 10.8% 11.4% -0.6%

Other… 1.9% 1.3% 0.7%

Total 100.0% 100.0%

TotalFuel

Page 39

7.1.1 Dispatched Generation* Fuel Mix by Region

65.6%

39.8%

14.6%

66.9%

45.1%

17.9%

12.5%

12.7%

29.0%

12.3%

11.8%

29.1%

15.8%

6.5%

53.7%

14.7%

7.1%

47.2%

4.5%

38.1%

4.5%

33.4%

1.6% 2.8%2.6%

1.6%2.5%

5.8%

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

120.0%

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

Oct-2017 Nov-2017

Coal(%) Nuclear(%) Gas(%) Wind(%) Other(%)

*Based on 5-minute unit level generation dispatch target Energy from gas-fired units++ made up approximately 20.6% of total MISO generation in

November 2017. In comparison, gas’ share++ of total generation was about 23.9% in October 2017.

The share of wind in the North Region decreased from 38.1% last month to 33.4% this month. While the share of coal generation in that region increased from 39.8% to 45.1%.

++ Total of Gas and Oil/Gas units.

Page 40

7.2 Fuel Price Information Fuel is the largest single expense for the generation of electricity. In November, gas

prices increased relative to last month. The table shows the nominal monthly average of fuel prices in $/MMbtu.

Month

Illinois

Basin

Coal

Powder

River

Basin

Coal

Chicago

Citygate

Hub

Gas

Henry

Hub

Gas Oil

Nov-16 1.41 0.51 2.42 2.46 12.11

Dec-16 1.45 0.60 3.63 3.55 12.26

Jan-17 1.48 0.65 3.27 3.30 12.95

Feb-17 1.34 0.66 2.82 2.83 12.92

Mar-17 1.34 0.65 2.84 2.83 12.34

Apr-17 1.31 0.67 2.99 3.08 12.99

May-17 1.31 0.66 3.00 3.13 12.21

Jun-17 1.31 0.66 2.80 2.94 11.48

Jul-17 1.30 0.65 2.82 2.96 11.79

Aug-17 1.30 0.66 2.81 2.88 12.95

Sep-17 1.31 0.66 2.89 2.98 12.88

Oct-17 1.38 0.67 2.80 2.86 13.42

Nov-17 1.38 0.68 3.00 2.98 13.85

To Last Month 0.0% 1.5% 7.1% 4.1% 3.2%

To Last Year -2.1% 33.0% 23.9% 21.0% 14.4%

Page 41

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

Nov-1

5

Dec-1

5

Jan

-16

Fe

b-1

6

Ma

r-1

6

Apr-

16

Ma

y-1

6

Jun

-16

Jul-1

6

Aug

-16

Sep

-16

Oct-

16

Nov-1

6

Dec-1

6

Jan

-17

Fe

b-1

7

Ma

r-1

7

Apr-

17

Ma

y-1

7

Jun

-17

Jul-1

7

Aug

-17

Sep

-17

Oct-

17

Nov-1

7

$/M

Mb

tu

Months

Nominal and Real Illinois Basin Coal PricesPeriod: November 2015 - November 2017, Price Index=2000

Nominal RealIllinois Basin Coal Heat Content: 11,800 btu/lb

As shown above, the nominal and inflation adjusted Illinois Basin coal6 prices stayed

relatively flat for most of 2017. In November 2017, the nominal prices decreased by 2.1% and the inflation-adjusted prices decreased by 6.8% compared to November 2016.

As shown above, the Powder River Basin6 nominal coal prices had been on an increasing trend since September 2016, but now have been fairly stable since February 2017. In November 2017, the nominal and the inflation-adjusted prices increased by roughly 33.0% and 26.5%, respectively, compared to last November.

6 http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html#spot

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

Nov-1

5

Dec-1

5

Jan

-16

Fe

b-1

6

Ma

r-1

6

Apr-

16

Ma

y-16

Jun

-16

Jul-1

6

Aug

-16

Sep

-16

Oct-

16

Nov-1

6

Dec-1

6

Jan

-17

Fe

b-1

7

Ma

r-1

7

Apr-

17

Ma

y-17

Jun

-17

Jul-1

7

Aug

-17

Sep

-17

Oct-

17

Nov-1

7

$/M

Mb

tu

Months

Nominal and Real Powder River Basin Coal PricesPeriod: November 2015 - November 2017, Price Index=2000

Nominal RealPowder River Basic Coal Heat Content: 8,800 btu/lb

http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html#spot

Page 42

0

1

2

3

4

5

6

Nov-1

5

Dec-1

5

Jan

-16

Fe

b-1

6

Ma

r-1

6

Apr-

16

Ma

y-1

6

Jun

-16

Jul-1

6

Aug

-16

Sep

-16

Oct-

16

Nov-1

6

Dec-1

6

Jan

-17

Fe

b-1

7

Ma

r-1

7

Apr-

17

Ma

y-1

7

Jun

-17

Jul-1

7

Aug

-17

Sep

-17

Oct-

17

Nov-1

7

$/M

Mb

tu

Months

Natural Gas Prices at Chicago HubPeriod: November 2015 - November 2017, Price Index=2000

Nominal Real

`

0

1

2

3

4

5

6

7

8

Nov-1

5

Dec-1

5

Jan

-16

Fe

b-1

6

Ma

r-1

6

Apr-

16

Ma

y-1

6

Jun

-16

Jul-1

6

Aug

-16

Sep

-16

Oct-

16

Nov-1

6

Dec-1

6

Jan

-17

Fe

b-1

7

Ma

r-1

7

Apr-

17

Ma

y-1

7

Jun

-17

Jul-1

7

Aug

-17

Sep

-17

Oct-

17

Nov-1

7

$/M

Mb

tu

Months

Natural Gas Prices at Henry HubPeriod: November 2015 - November 2017, Price Index=2000

Nominal Real

`

After reaching a bottom in March 2016 Natural Gas prices have been on an increasing

trend. This month at the Chicago Citygate Hub, the nominal price increased by 7.1% and the

Page 43

inflation-adjusted price rose by 8.2% compared to October 2017. This month at the Henry Hub the nominal price increased by 21.0% and the inflation-adjusted price increased by 15.1% compared to November 2016.

2

4

6

8

10

12

14

16

18

20

22

Nov-1

5

Dec-1

5

Jan

-16

Fe

b-1

6

Ma

r-1

6

Apr-

16

Ma

y-16

Jun

-16

Jul-1

6

Aug

-16

Sep

-16

Oct-

16

Nov-1

6

Dec-1

6

Jan

-17

Fe

b-1

7

Ma

r-1

7

Apr-

17

Ma

y-17

Jun

-17

Jul-1

7

Aug

-17

Sep

-17

Oct-

17

Nov-1

7

$/M

Mb

tu

Months

Distillate Fuel OilPeriod: November 2015 - November 2017, Index=2000

Nominal RealDistillate Fuel Oil Heat Content: 5.825 mmbtu/barrell

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 (non-transportation) applications in the commercial, industrial, and electricity generation sectors.

The nominal and real Distillate Fuel Oil7 prices have been on an increasing trend since February 2016.

The November 2017 nominal prices have risen relative to November 2016. This month,

the nominal oil prices increased by 14.4%, while the real (i.e. inflation adjusted) oil prices increased 8.8% compared to last month.

7http://www.eia.gov/forecasts/steo/tables/?tableNumber=8#endcode=201212&periodtype=m&startcode=200801

http://www.eia.gov/steo/cf_tables/steotables.cfm?tableNumber=8&loadAction=Apply+Changes&periodType=Monthly&startYear=2008&endYear=2012&startMonth=1&startMonthChanged=false&startQuarterChanged=false&endMonth=12&endMonthChanged=false&endQuarterChanged=false&noScroll=true

Page 44

Section 8: Wind Utilization

Wind energy, unlike other fuel types, can be intermittent and highly variable. Because instantaneous electrical generation and consumption must remain in balance to maintain grid stability, the properties of wind may present challenges to incorporating large amounts of wind power into a grid system. As a result, uncertainty associated with wind generation output can affect market prices.

On June 1st, 2011, MISO successfully launched Dispatchable Intermittent Resources (DIRs) which treat renewable energy resources like any other generation resource and, allow participation in the Real-Time energy market.

The charts below illustrate monthly energy contributions from dispatchable and non-dispatchable wind to the MISO grid system, as well as monthly wind capacity factors.

8.1 Wind8 Contribution

584 764532 652 657 569 510 423 247 227 417

669 649

4,090

4,923

3,713

4,3754,630

4,1963,895

3,349

2,030 1,900

2,982

4,7184,423

4,674

5,687

4,245

5,0275,287

4,764

4,405

3,772

2,2772,127

3,399

5,387

5,072

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000


GW

h

Monthly Energy Contribution from Wind

Dispatchable Intermittent Resources (DIR)

Non Dispatchable Intermittent Resources (non-DIR)

Total Wind generation decreased from 5,387 GWh last month to 5,072 GWh this month. The registered wind generation capacity factor was 41.2% this month.

November wind production accounted for approximately 10.8% of MISO’s total energy, while it was 10.5% in November 2016 and 11.4% in October 2017.

Hourly wind generation exceeded 9,000 MW in 227 hours in November 2017. For comparison, hourly wind generation exceeded 9,000 MW in 195 hours in November 2016.

DIR participation accounted for 87.2% of the total wind generation this month. Following the unit dispatch, 3.8% of DIRs were dispatched down due to congestion.

8 Based on Hourly State Estimator Data

Page 45

810 1,027 714 971 883 790 686 588 332 305 579 899 902

5,681

6,617

4,991

6,5106,223

5,8275,235

4,651

2,729 2,553

4,141

6,341 6,143

6,491

7,643

5,705

7,4817,106

6,617

5,921

5,239

3,0612,858

4,720

7,241 7,044

16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.316.8 16.8 16.8

17.1

13.8 13.8 13.8 13.8 13.8 13.8 13.8 13.8 13.814.3 14.3 14.3

14.6

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000


Reg

iste

red

Win

d C

ap

acit

y (

GW

)

Win

d E

nerg

y P

rod

ucti

on

(M

W)

Hourly Average Wind Energy Production

Non-DIR Energy Production (MW) DIR Energy Production (MW)

Registered Wind Capacity (GW) Registered DIR Capacity (GW) 8.2 Wind Capacity Factor The capacity factors of other generating plants are based mostly on respective fuel cost. The capacity factor of wind energy is determined primarily by meteorological conditions.

39.9%

46.9%

35.0%

45.8%43.5%

40.5%

36.3%

31.3%

18.3% 17.1%

27.6%

42.3% 41.2%

0%

10%

20%

30%

40%

50%

60%

70%


Pe

rce

nt

Monthly Wind Capacity Factor

The total registered wind capacity in November 2017 was 17,104 MW. The wind capacity

factor decreased from 42.3% last month to 41.2% this month.

* Wind Capacity factor is calculated by taking the average of hourly actual wind generation divided by registered capacity.

Page 46

Section 9: Outages Outages can directly affect congestion, resource availability, and prices. Prices are sensitive to generation outages because they affect market dynamics by changing supply and demand conditions.

9.1 Generation Outages9

Forced and Planned outages in the chart below are reflective of the MISO Reliability footprint. This month planned generator outages decreased 30.0% and forced generator outages

decreased 7.0% relative to last month. In comparison with November 2016, planned generator outages decreased 13.5% and

forced generator outages decreased 1.7%.

Net Available Capacity is calculated as Reliability Generation Capacity^^ minus Total Outages.

0%

10%

20%

30%

40%

50%

60%

70%

80%

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000


Perc

en

t

MW

Month

Generation Outages by Type - Reliability Footprint

Period: November 2016 - November 2017

Forced** Planned** Outages as % of Net Available Capacity

9 Outage data include all units in the MISO Market and Reliability footprints. Outages scheduler is “point in time” and the data can change based

on entry. The chart reflects the monthly data as it resided in the system on the date of extraction.

Generation outage data was extracted on December 18th

2017 from the CROW Outage Scheduler system.

**Forced Outages include Emergency, Forced, and Urgent **Planned Outages include Planned ^^Reliability Generation Capacity sourced from the MISO Corporate Fact Sheet

Page 47

9.2 Transmission Outages10

Type kV Nov-17 Oct-17

Forced <= 69 236 279

Forced >69 & <=138 664 694

Forced >138 & <=230 263 339

Forced >230 & <=345 110 129

Forced >345 & <500 1 0

Forced >=500 47 39

Planned <= 69 734 790

Planned >69 & <=138 2144 2279

Planned >138 & <=230 924 876

Planned >230 & <=345 414 535

Planned >345 & <500 7 10

Planned >=500 153 129

Number of Transmission Outage Entries - Reliability Footprint

10

Line outage entries in MISO Reliability Footprint

November 2017 transmission outage data was extracted on December 8th

, 2017.

Note: Forced Outages include Emergency, Forced, Discretionary, and Urgent Planned Outages include Planned, Opportunity

Page 48

Section 10: Cost and Dispute Summary

Cost by Charge Type

Charge Type Charge Code Nov-16 Oct-17 Nov-17

RT Net Inadvertent RT_NI_DIST $987,065 $570,358 $1,114,542

RT Revenue Neutrality RT_RNU $7,265,942 $13,505,945 $8,093,247

RT RSG RT_RSG_DIST1 $2,018,819 $5,202,448 $3,095,960

DA RSG DA_RSG_DIST $2,600,274 $3,990,708 $1,911,208 Data Source: Settlements Figures may change due to resettlement.

These amounts continue to change each month until the S-105 (settlement) is completed for the last day of the month.

This month, Real-Time RSG make-whole payment (MWP) decreased 40.5% relative to October 2017 and increased 53.4% since November 2016.

− The portion of Real-Time RSG associated with constraint mitigation increased from 19.0% in October 2017 to 26.8% this month.

This month, Day-Ahead RSG make-whole payment (MWP) decreased 52.1% relative to

October 2017 and decreased by 26.5% relative to November 2016. − Day-Ahead RSG associated with VLR commitments increased from 66.0% of the

total Day-Ahead RSG in October 2017 to 37.6% in November.

Page 49

November 2017 Dispute Summary October 2017 Dispute Summary

As of 12/18/2017 As of 12/08/2017

Dispute Type $$ Count Dispute Type $$ Count

ARS 41552.12 65 ARS 41552.12 65

ASM CHARGE 141898.82 341 ASM CHARGE 141898.82 341

ENERGY 8331633.64 787 ENERGY 8295358.6 776

FSS 7317111.87 243 FSS 7317111.87 243

FTR 7257216.78 156 FTR 7257216.78 156

Invoice 6540679.35 12 Invoice 6540679.35 12

LOSSES 440864.4 16 LOSSES 440864.4 16

MWP 61723397.83 619 MWP 61718946.99 618

NAI 5135850.22 252 NAI 5135850.22 252

OTHER 75780754.58 867 OTHER 75780754.58 867

PSS 52850528 2201 PSS 52848144.82 2198

RESERVE 334666.84 142 RESERVE 334666.84 142

RSG 235108597.1 10544 RSG 235108597.1 10544

RSG1 1635431.12 1401 RSG1 1613635 1388

UD 6214708.05 2089 UD 6214708.05 2089

Total 468,854,890.68$ 19,735 Total 468,789,985.50$ 19,707

Granted/Closed Dispute Summary Granted/Closed Dispute Summary

Dispute data is cumulative from April 2005 and reflects the monthly data as it resided in the system on the date of extraction. Date of Extraction: December 18

th, 2017.

28 disputes were granted/closed in November 2017.

Page 50

Section 11: Ramp Capability Product Summary MISO’s Ramp Capability Product began on May 1st, 2016. MISO is the first RTO/ISO to successfully develop and implement a co-optimized ramp product, which provides more transparent price signals to help manage ramp constraints that otherwise could lead to short-term reserve scarcity events. This product provides a market-based approach to better position resources with ramp capability in order to manage net load variations and uncertainties. This bi-directional product is included both the Day-Ahead and Real-Time markets. 11.1 Market Clearing Price Trend A single-segment Ramp Capability Demand Curve of $5/MWh is developed to represent ramp clearing and associated price impact when system is short of ramp. The market clearing prices, which are the marginal costs to meet ramp capability requirements, provide economic incentives for resources to supply ramp capability and facilitate investment in flexible resources.

Monthly Average of Ramp Capability Product Market Clearing Prices

0.3

8

0.4

0

0.3

8

0.1

3

0.6

3

1.1

9

0.8

6

0.6

3

0.8

7

0.8

4

0.7

8

0.7

6

0.5

5

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.2

1

0.1

5 0.2

5

0.1

0

0.3

2

0.3

3

0.3

5

0.1

4

0.3

4

0.2

6

0.2

7 0.3

3

0.3

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

$ p

er

MW

h

DA Ramp Up DA Ramp Down RT Ramp Up RT Ramp Down

In November 2017, the average Market Clearing Prices for the DA Ramp Up and RT Ramp Up were $0.55/MWh and $0.30/MWh, respectively. The low prices are expected since the system is ramp-sufficient in most intervals, and the Ramp MCP is zero in those intervals. The Ramp Down average MCPs for both DA and RT were zero, also as expected.

Page 51

11.2 Market Clearing Price Analysis The table below shows the hourly summary statistics for MISO system-wide ramp capability product MCPs.

Type Maximum Average Minimum

Standard

Deviation

Coefficient of

Variation (CV)

RAMP_UP_DA_MCP $5.00 $0.55 $0.00 $1.27 231.49%

RAMP_DOWN_DA_MCP $0.00 $0.00 $0.00 $0.00 0.00%

RAMP_UP_RT_MCP $4.61 $0.30 $0.00 $0.81 274.21%

RAMP_DOWN_RT_MCP $0.00 $0.00 $0.00 $0.00 0.00% This month, the maximum DA Ramp Up MCP was $5.00/MWh and the maximum RT Ramp Up MCP on hourly average basis was $4.61/MWh.

0

5

10

15

20

25

30

35

40

45

50

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

11

/1

11

/2

11

/3

11

/4

11

/5

11

/6

11

/7

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/8

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/9

11

/10

11

/11

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/13

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/14

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/15

11

/16

11

/17

11

/18

11

/19

11

/20

11

/21

11

/22

11

/23

11

/24

11

/25

11

/26

11

/27

11

/28

11

/29

11

/30

MW

$/M

Wh

MISO Ramp Up MCPs and Deficit MWs November 2017

Avg DA Ramp Up Deficit (MW) Avg RT Ramp Up Deficit (MW)

Avg DA Ramp Up MCP ($/MWh) Avg RT Ramp Up MCP ($/MWh)

This month, the correlation between the daily average DA Ramp Up MCPs and DA Ramp Up deficits is 0.54. While the correlation between the daily average RT Ramp Up MCPs and RT Ramp Up deficits is 0.91.

Page 52

11.3 Hourly Average RT Ramp Requirement

171

345

476

593

832

1,1

55

1,3

41

1,0

02

714

675

606

522

494

519

529

546

763

1,1

00

741

406

335

170

87 1

33

1,0

35

812

675

558

349

124

67

236

444

480 546 6

30

659

633

621

604

389

126

417

748 8

23

1,0

26 1,1

27

1,0

71

0

200

400

600

800

1000

1200

1400

1600

1800

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MW

Hour

Real-Time Ramp Requirement by Hour of Day

November 2017

Ramp Up Requirement Ramp Down Requirement

The highest hourly average RT ramp up requirement was in HE 7, which was 1,341 MW.

The highest hourly average RT ramp down requirement was in HE 23, which was 1,127

MW.

November 2017 Monthly Market Assessment Report Monthly Report... · Peak hour Load2 and Real-Time Daily Integrated Peak Load hour Generation Dispatch target without Imports or Exports

Documents