IMM Quarterly Report: Summer 2020 · • MISO’s summer peak load slightly above 117 GW occurred on August 24. ... We have recommended VOLL for shortage pricing of $23,000 so we

IMM Quarterly Report:

Summer 2020

MISO Independent Market Monitor

David Patton, Ph.D.

Potomac Economics

September 15, 2020

-2-© 2020 Potomac Economics

• The MISO markets performed competitively this Summer, market power mitigation was infrequent, and conduct was competitive overall.

• A continuing trend of low natural gas prices in the first two months contributed to energy prices falling 6 percent compared to last summer.

✓ Gas prices averaged less than $2 per MMBTU this quarter, rising in August.

• MISO’s summer peak load slightly above 117 GW occurred on August 24.

✓ Average load remained consistent with prior summers, as COVID-related impacts diminished and were offset by hotter temperatures.

• MISO experienced several significant events this summer.

✓ In Michigan, MISO declared a Local Transmission Emergency in June and a Transmission System Emergency in July, resulting in very high congestion.

✓ MISO experienced a week of hot temperatures in early July and on July 7, it declared a Maximum Generation Event in the Midwest region.

✓ In Western WOTAB on Aug 27, MISO declared an emergency and cut load.

– Prices were finalized a week after the event and set at the VOLL.

✓ MISO also declared on Local Transmission Emergency in Texas on August 28 that was caused by storm-related transmission outages.

Highlights and Findings: Summer 2020


Quarterly Summary

Value

Prior

Qtr.

Prior

Year Value

Prior

Qtr.

Prior

Year

RT Energy Prices ($/MWh) $24.36 32% -6% FTR Funding (%) 101% 99% 96%

Fuel Prices ($/MMBtu) Wind Output (MW/hr) 6,128 -25% 44%

Natural Gas - Chicago $1.76 8% -15% Guarantee Payments ($M)4

Natural Gas - Henry Hub $1.83 7% -19% Real-Time RSG $16.6 153% 14%

Western Coal $0.68 -2% -3% Day-Ahead RSG $5.7 -9% -1%

Eastern Coal $1.24 2% -18% Day-Ahead Margin Assurance $10.9 94% 173%

Load (GW)2 Real-Time Offer Rev. Sufficiency $1.1 176% 55%

Average Load 83.6 29% 0% Price Convergence5

Peak Load 117.5 28% -3% Market-wide DA Premium -1.1% 2.6% 0.3%

% Scheduled DA (Peak Hour) 100.3% 98.8% 99.3% Virtual Trading

Transmission Congestion ($M) Cleared Quantity (MW/hr) 16,715 -8% 4%

Real-Time Congestion Value $331.0 41% 23% % Price Insensitive 28% 33% 32%

Day-Ahead Congestion Revenue $222.6 75% 47% % Screened for Review 1% 1% 1%

Balancing Congestion Revenue3 $75.5 $6.5 $4.6 Profitability ($/MW) $0.30 $0.70 $0.32

Ancillary Service Prices ($/MWh) Dispatch of Peaking Units (MW/hr) 2,569 829 1775

Regulation $7.86 -2% 3% Output Gap- Low Thresh. (MW/hr) 191 55 45

Spinning Reserves $1.90 -11% -12% Other:

Supplemental Reserves $0.30 85% -51%

Key: Expected Notes:

Monitor/Discuss

Concern

5. Values include allocation of RSG.

3. Net real-time congestion collection, unadjusted for M2M settlements.

4. Includes effects of market power mitigation.

Change1

Change1

1. Values not in italics are the values for the past period rather than the change.

2. Comparisons adjusted for any change in membership.


Hot Week in Early July (Slides 21-25)

• Between July 1-10, MISO issued Hot Weather Alerts and Capacity Advisories for the Midwest due to high temperatures and humidity.

• Long-lead commitments. On July 1, MISO forecasted operating margins in the Midwest of only 4 and 3 percent on July 6 and 7, respectively.

✓ MISO committed long-lead time units in the South to ensure power could be transferred as needed to the Midwest – resulted in > $800,000 in RSG.

✓ From July 1-9, more than 1,700 MW on average were trapped in the South in the peak hours between 2 p.m. and 4 p.m. so their usefulness was limited.

✓ The implied VOLL for these commitments exceeded $40,000 per MWh. We have recommended VOLL for shortage pricing of $23,000 so we find these commitments conservative, but not unreasonable.

• Forecast Errors. MISO’s load forecast was impacted on multiple days because of large storms, causing significant forecast errors.

✓ Day-ahead forecast errors were as high as 8 and 7 percent on July 8 and 10.

Highlights for Summer 2020


Hot Week in Early July (cont.)

• July 6. Conditions were tighter on July 6 than any other day of the week.

✓ Although temperatures and load were not quite as high on this day, wind output was very low.

✓ MISO declared conservative operations but did not proceed to an emergency.

• July 7. At 1 p.m., MISO declared a Max Gen Event that quickly escalated to an Emergency Event in the North and Central Regions.

✓ The emergency led to the commitment of all available resources.

✓ Morning temperatures rose more than expected, but storms flattened the load.

✓ Ultimately, this caused: a) the emergency declaration to be unnecessary and b) the 433 MW of emergency-only resources to not set prices.

• July 8. July 8 was the hottest day of the week and exhibited the highest day-ahead forecasted load.

✓ Conditions ultimately were not tight because the load came in much lower than forecast; and

✓ Wind output was very high and led to a large supply margin on this day.



Summer Capacity Availability (Slides 26-28)

• Currently, resource accreditation is based primarily on forced outages.

• In reality, a large share of the resources procured in the PRA are ultimately unavailable for reasons other than forced outage.

• On July 7, almost 15 GW was unavailable because of outages and derates.

✓ The largest share of the unavailable MWs were in Zone 7.

✓ In MISO’s 2020-2021 PRA, Zone 7 cleared at CONE ($257.53/MW-day).

✓ Several capacity resources in Zone 7 were unavailable or derated during most of the summer, affecting congestion and prices in Michigan.

✓ Two of these resources were together paid more than $154 million in the PRA.

• We continue to recommend that MISO reform capacity accreditation to reflect the actual availability of resources during MISO’s tightest hours.

✓ The average capacity derates in Zones 6 and 7 were 8.9 and 8.2 in the PRA.

✓ The actual average derates (including outages) of conventional resources in the tightest hours in July in these zones were 23.5 and 28.4 percent, respectively.



Increased Congestion and Michigan Tx Emergencies (Slides 27-28, 30-31)

• Although gas prices remained low in June and July, day-ahead and real-time congestion rose 47 and 23 percent over last year, respectively.

• More than $45 million in increased congestion was attributable to low generation availability in Michigan, including almost $35 million on 2 days.

✓ On June 10, MISO declared a Local Transmission Emergency from 11:25 a.m. to 5:20 p.m. to access 260 MW of emergency generation.

✓ On July 9, MISO declared a Transmission System Emergency from 4:10 p.m. to 7 p.m. for two parallel constraints to access emergency ranges.

– IESO was in EEA 1 and had reduced imports to Michigan by 700 MW.

✓ A critical unit that would have provided significant congestion relief was unavailable during both events because of a COVID outbreak at the unit.

• Over $10 million in day-ahead congestion accrued in Texas on August 28 because of the hurricane-related system effects.

• MISO has made progress in discussing TLR procedures with IESO.



August Load Shed in the Western Load Pocket

• On August 27, Hurricane Laura forced out several transmission lines and more than 6,000 MW of generation in Eastern Texas and Western Louisiana.

✓ MISO declared an emergency and shed > 500 MW of firm load in the Western load pocket.

✓ The results of this event raise energy and capacity market concerns.

• Energy Market. Ex ante prices averaged $15 per MWh throughout the event and did not reflect the shortages.

✓ Operators had to manually re-dispatch multiple units.

✓ MISO set ex post prices in the Western Load Pocket a week later to reflect the current value of lost load (VOLL) of $3,500 for several hours.

✓ MISO’s current VOLL of $3,500 per MWh is inefficiently low. MISO would have lost of up to 830 MW from a key resource to ERCOT if it had been tight, since ERCOT will set prices up to $9,000 per MWh.

✓ We have recommended that MISO update the VOLL used in shortage pricing based on data from the Midwest to $23,000 per MWh.



August Load Shed in Western Load Pocket (Cont.)

• Capacity Market. We continue to be concerned that the capacity market zones do not reflect these load pockets that are very tight.

✓ We have been recommending MISO define local capacity zones consistent with electrical constraints in order to send better economic signals.

✓ The capacity market does not reflect the Western Load Pocket and, thus, produced inefficient results for this area in the 2020-2021 PRA.

– 885 MW of UCAP cleared at $6.88 per MW-day (very close to zero), down from almost 1,200 MW the prior year.

– A large resource that straddles MISO and ERCOT and could have provided an additional 800 MW of UCAP did not clear the 2020-2021 PRA.

✓ Fortunately, this resource switched to MISO and provided energy to the pocket on August 27 or the load shed would have been larger.

• Additional Effects of Laura. On August 28, MISO declared an LTE from roughly 9:30 a.m to 7:30 p.m. in Eastern Texas due to damage from the hurricane.



Coal Commitment and Dispatch Study

• We are completing a study of coal resource commitments and dispatch to evaluate recent concerns raised that they are running uneconomically.

• Our study finds that most coal resources are started economically:

✓ 90 percent were economic in 2016-2018 on the day they started, with roughly half offered economically and half scheduled as “must-run”.

✓ This share fell in 2019 as natural gas prices declined, making it more difficult to predict when the coal resources will be economic.

✓ Merchant resources started economically 99 percent of the days they started.

✓ Roughly 20 percent of the uneconomic starts appeared to be economic based on the prices on the day prior to the start.


Starts % of Starts Starts % of Starts

All Coal Resources 5882 1800

Economic Starts 5270 90% 1497 83%

Offered Economically 2553 43% 730 41%

Must-Run and Economic 2717 46% 767 43%

Uneconomic Starts 612 10% 303 17%

Not Expected to be Economic 491 8% 239 13%

Expected to be Economic 121 2% 64 4%

2016-2018 2019


Coal Commitment and Dispatch Study (cont.)

• The most significant decision coal resources make is whether to stay online each day after they start.

• This decision is complicated by the costs of cycling the units – when a unit turns off, it must then incur a start-up cost to come back on.

• We evaluated the decision to run each day and found:

✓ The decision to stay on by integrated utilities was efficient 96 percent of the time, although they were only profitable on 80 percent of these days.

✓ The unprofitable days that are efficient reflect periods when the transitory losses of staying on are less than the cycling costs of turning off.

✓ Again, the conduct of merchant generators was more economic than their regulated counterparts.


Efficient Not Efficient Efficient Not Efficient

Profitable 80% 0% 96% 0% Profitable

Unprofitable 16% 4% 4% 0% Unprofitable

96% 4% 100% 0%

Integrated Utilities Merchants


Progress on Improving Transmission Ratings

• We continue to promote the use of ambient temperature-adjusted ratings (AARs) and short-term emergency ratings – as we’ve shown in our SOM reports, the benefits have averaged almost $150 million per year.

• We’ve been meeting with the TOs, individual states and OMS.

• The states are recognizing the value of fuller utilization of the transmission system for their customers, and on August 13, OMS issued a position Statement on Enhanced Line Ratings.** It calls for TOs to:

✓ Provide greater transparency and consistency in line ratings and methods.

✓ Provide both normal and emergency ratings to MISO per the TO Agreement.

✓ Develop procedures for identifying facilities for enhanced line ratings.

• Although valuable discussions are taking place and there has been little technical disagreement, progress has been very limited to date.

• MISO has participated in some of the meetings but has devoted very few resources to this effort – more will be needed from MISO to make progress.

**https://www.misostates.org/images/PositionStatements/OMS_Position_Statement__Enhanced_Line_Ratings.pdf


https://www.misostates.org/images/PositionStatements/OMS_Position_Statement__Enhanced_Line_Ratings.pdf


• The IMM function has not experienced detrimental impacts from COVID-19.

• We responded to several FERC questions related to prior referrals and FERC

investigations. We continued to meet with FERC on a weekly basis and we

responded to several requests for information on market issues.

• In June, we presented a summary of MISO South market results and issues to

the Entergy Regional State Committee.

• We filed comments in June in the FERC NOPR Incentives requesting FERC

consider alternative incentives for existing transmission (other than ROE).

• In July, we presented the Spring Quarterly Report and the 2019 SOM

Recommendations to the MSC.

• We participated in a FERC conference of the RTO market monitors in July,

making presentations on FTR markets, RTO credit practices, and the evolving

generation portfolios.

Submittals to External Entities and Other Issues


• We completed work with the SPP MMU and MISO on the Tier 1 and Tier 2

items and presented the results to the OMS.

✓ We published the Tier 2 Interface Pricing study in August and presented it to

OMS/RSC in September.

✓ Additional items in Tier 2 and Tier 3 may be considered in the future if

approved by the Markets Committee.

• We continue discussing issues with Emergency Pricing and Shortage Pricing

with MISO and the MSC

✓ These discussions included the elimination of offline ELMP pricing, which

artificially mutes MISO’s shortage pricing.

• We continued working with MISO on proposed improvements to the market

power mitigation measures in Module D of the Tariff at the MSC.

✓ We will also be supporting MISO’s re-filing of the physical withholding

provision in Module D with an affidavit.

Submittals to External Entities and Other Issues


Day-Ahead Average Monthly Hub Prices

Summer 2018-2020

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$0

$10

$20

$30

$40

$50

Jun Jul Aug Jun Jul Aug Jun Jul Aug

Summer 2018 Summer 2019 Summer 2020

Na

tura

l G

as

Pri

ce (

$/M

MB

tu)

$/M

Wh

Mean Gas Price Texas Hub

Arkansas Hub Louisiana Hub

Minnesota Hub Indiana Hub

Michigan Hub


All-In Price

2018-2020

$0

$2

$4

$6

$8

$10

$0

$10

$20

$30

$40

$50

18 19 20 J J A S O N D J F M A M J J A S O N D J F M A M J J A

Summer 2018 2019 2020

Na

tura

l G

as

Pri

ce (

$/M

MB

tu)

All

-In

Pri

ce (

$/M

Wh

)

Capacity-Michigan Capacity Ancillary Services Energy (Shortage) Energy (Non-shortage) Uplift Natural Gas Price


Ancillary Service Prices

Summer 2019 – 2020

-$3

$0

$3

$6

$9

$12

$15

J J A S O N D J F M A M J J A J J A S O N D J F M A M J J A J J A S O N D J F M A M J J A

2019 2020 2019 2020 2019 2020

Regulation Spinning Reserve Supplemental Reserve

$/M

Wh

Regulation Price (excl. shortages)

Impact from Reg Shortages

Spinning Reserve Price (excl. shortages)

Impact from Spin Shortages

Supp Reserve Price (excl. shortages)

Impact of Supp Res. Shortages

Day-Ahead Premium

5-Year Summer Average


MISO Fuel Prices

Summer 2018-2020

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

J J A S O N D J F M A M J J A S O N D J F M A M J J A

$/M

MB

tu

2018 2019 2020

$7.43$9.13

2018 2019 2020

Chicago NG $2.76 $2.07 $1.76

Henry NG $2.89 $2.27 $1.83

Summer Average 2018 2019 2020

IB Coal $1.58 $1.52 $1.24

PRB Coal $0.71 $0.70 $0.68

Summer Average


Load and Weather Patterns

Summer 2018-2020

Notes: Midwest degree day calculations include four representative cities in the Midwest: Indianapolis, Detroit, Milwaukee and Minneapolis.

The South region includes Little Rock and New Orleans.

0

17,000

34,000

51,000

68,000

85,000

102,000

119,000

136,000

0

500

1,000

1,500

2,000

2,500

3,000

18 19 20 18 19 20 18 19 20 18 19 20

Summer Jun Jul Aug

Lo

ad

(M

W)

Ad

just

ed D

egre

e D

ay

s

CDDs

HDDs

Average Load

Historical Avg.

Peak Load


Capacity, Energy and Price Setting Share

Summer 2019-2020

Summer

2019 2020 2019 2020 2019 2020 2019 2020 2019 2020

Nuclear 12,225 12,107 10% 9% 16% 15% 0% 0% 0% 0%

Coal 48,775 46,864 38% 37% 40% 38% 51% 43% 93% 90%

Natural Gas 55,240 56,673 43% 44% 35% 37% 46% 55% 98% 97%

Oil 1,691 1,568 1% 1% 0% 0% 0% 0% 0% 1%

Hydro 3,966 4,034 3% 3% 2% 2% 2% 1% 4% 4%

Wind 3,005 3,660 2% 3% 6% 8% 1% 0% 23% 50%

Other 2,678 2,703 2% 2% 1% 1% 0% 0% 2% 7%

Total 127,580 127,608

SMP (%) LMP (%)

Price SettingUnforced Capacity

Total (MW) Share (%) Share (%)

Energy Output


Hot Week in Early July

Daily High Temperatures

Hist.

Avg. 6 7 8 9

Detroit 83 92 95 91 92

Indianapolis 85 92 91 94 91

Milwaukee 80 93 93 89 88

Minneapolis 84 86 88 93 82

Little Rock 92 92 91 88 90

New Orleans 92 82 88 94 96

July



Midwest Region

Day-Ahead

Forecast

0

10,000

20,000

30,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

12:0

0 P

M

1:0

0 P

M

2:0

0 P

M

3:0

0 P

M

4:0

0 P

M

5:0

0 P

M

12:0

0 P

M

1:0

0 P

M

2:0

0 P

M

3:0

0 P

M

4:0

0 P

M

5:0

0 P

M

12:0

0 P

M

1:0

0 P

M

2:0

0 P

M

3:0

0 P

M

4:0

0 P

M

5:0

0 P

M

12:0

0 P

M

1:0

0 P

M

2:0

0 P

M

3:0

0 P

M

4:0

0 P

M

5:0

0 P

M

12:0

0 P

M

1:0

0 P

M

2:0

0 P

M

3:0

0 P

M

4:0

0 P

M

5:0

0 P

M

7/6/2020 7/7/2020 7/8/2020 7/9/2020 7/10/2020

MW

10,000

0

20,000

+2 Hour

Forecast

Load +

Reserve

Requirement

Max Gen

Total

Available

Supply

Emrg. MW

Off < 2 Hr

Stranded

Long Lead

Online Gen.

Wind

NSI

Forced Otgs

Planned Otgs

Derates

Off > 2 Hr


Maximum Generation Event on July 7, 2020

Midwest Region

0

20,000

40,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

12

:00 A

M1

2:3

0 A

M1

:00

AM

1:3

0 A

M2

:00

AM

2:3

0 A

M3

:00

AM

3:3

0 A

M4

:00

AM

4:3

0 A

M5

:00

AM

5:3

0 A

M6

:00

AM

6:3

0 A

M7

:00

AM

7:3

0 A

M8

:00

AM

8:3

0 A

M9

:00

AM

9:3

0 A

M1

0:0

0 A

M1

0:3

0 A

M1

1:0

0 A

M1

1:3

0 A

M1

2:0

0 P

M1

2:3

0 P

M1

:00

PM

1:3

0 P

M2

:00

PM

2:3

0 P

M3

:00

PM

3:3

0 P

M4

:00

PM

4:3

0 P

M5

:00

PM

5:3

0 P

M6

:00

PM

6:3

0 P

M7:0

0 P

M7

:30

PM

8:0

0 P

M8

:30

PM

9:0

0 P

M9

:30

PM

10

:05 P

M1

0:3

5 P

M1

1:0

5 P

M

MW

10,000

0

+2H LAC

Forecast

Day-Ahead

Forecast

Load + Reserve

Requirement

Total

Supply

Max Gen Event

Emerg Gen

Off < 2 hour

Stranded MW

Long Lead

Online Gen

Wind

NSI

Forced Outages

Planned Outages

Derates

Offline > 2 Hr Lead


Peak Hour Midwest Capacity Availability

Midwest Region - July 7, Hour 16


Uplift by Commitment Time


$0

$250,000

$500,000

$750,000

$1,000,000

$1,250,000

$1,500,000

7/1

7/2

7/3

7/4

7/5

7/6

7/7

7/8

7/9

7/1

0

7/1

7/2

7/3

7/4

7/5

7/6

7/7

7/8

7/9

7/1

0

South Midwest

RS

G (

$)

Look-Ahead Commit (< 2.5 Hr)

Intra-Day Reliab. (> 2.5 Hr)

Day-Ahead Reliability

Day-Ahead Market

Multi-Day

RSG @ Reference


0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

-

5,000

10,000

15,000

20,000

25,000

$5.00 $5.00 $5.00 $5.00 $5.00 $5.00 $257.53 $4.75 $6.88 $4.75

1 2 3 4 5 6 7 8 9 10

Central / North South

MW

PRA Zones - Auction Prices

Auction

Clearing

Price

($/MW-

day)

UCAP

ICAP - UCAP

Availability (Average)

Availability (10% Tightest Margin Hours)

Planning Resource Availability

July 2020

* ICAP and UCAP based on data from PRA for 20/21 PY. Excludes intermittent resources (e.g., wind, solar) and LMRs. Tightest margin

hours in July based on difference between FRAC load forecast and max available MWs (including offline with less than 24-hour lead).


Resource Unavailability by Outage Category

July 2020 – Hour 16

* Unavailable MW based on the difference between ICAP (20/21 PY) and actual available MW. Excludes intermittent resources

(e.g., wind, solar) and LMRs.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

$5.00 $5.00 $5.00 $5.00 $5.00 $5.00 $257.53 $4.75 $6.88 $4.75

1 2 3 4 5 6 7 8 9 10

Central / North South

Un

av

ail

ab

le M

W

PRA Zones

Planned Unplanned Forced

Unreported Derate

Auction

Clearing

Price

($/MW-

day)


Planning Resource Availability in Zone 7

Largest 20 Units – July 2020

* ICAP and UCAP based on data from PRA for 20/21 PY. Excludes intermittent resources (e.g., wind, solar) and LMRs. Tightest margin

hours in July based on difference between FRAC load forecast and max available MWs (including offline with less than 24-hour lead).

-

200

400

600

800

1,000

1,200

1,400

A B C D E F G H I J K L M N O P Q R S T

MW

UCAP

ICAP - UCAP

Availability (Average)

Availability (10% Tightest Margin Hours)


Generation Outages and Deratings

Summer 2019-2020

0%

10%

20%

30%

40%

50%

60%

70%

Sum Fall Win Spr Sum Sum Fall Win Spr Sum Sum Fall Win Spr Sum

2019 2020 2019 2020 2019 2020

Total Outage Derate

Sh

are

of

Ca

pa

city

Midwest South Midwest South Midwest South

Forced: Long-Term 4.4% 5.2% 4.7% 4.7% 5.1% 3.5%

Forced: Short-Term 1.5% 1.6% 2.0% 1.7% 1.9% 1.5%

Unreported in CROW 5.2% 8.6% 5.3% 10.1% 5.1% 11.3%

Unplanned: Other 3.1% 3.2% 2.7% 1.8% 3.3% 2.4%

Planned: Extensions 0.8% 1.6% 1.5% 1.9% 1.5% 0.4%

Planned: Normal 4.1% 3.1% 4.5% 3.9% 4.9% 2.7%

Total 19.2% 23.3% 20.8% 24.0% 21.9% 21.8%

Sum Monthly Average2018 2019 2020


Day-Ahead Congestion, Balancing Congestion

and FTR Underfunding

-$15

$0

$15

$0

$25

$50

$75

$100

J F M A M J J A S O N D J F M A M J J A

2019 2020

2019 2020

Balancing Congestion Revenue ($4.6 M) ($75.5 M)

DA Congestion Revenues $151.1 M $222.6 M

FTR Surplus (Shortfall) ($13.1 M) $5.8 M

FTR Funding (%) 96.2% 101.2%

Summer Totals -$89M


Value of Real-Time Congestion

Summer 2019-2020

$0

$25

$50

$75

$100

$125

$150

$175

$200

18 19 20 J J A S O N D J F M A M J J A

Sum. Avg. 2019 2020

Co

ng

esti

on

Va

lue

(Mil

lio

ns)

Totals Sum. 19 Spr. 20 Sum. 20

Midwest $183.5 M $186.9 M $279.2 M

Transfer Constraints $6.2 M $3.4 M $7.7 M

South $79.7 M $43.9 M $43.8 M

Total RT Value $269.4 M $234.2 M $330.6 M

DA Congestion Revenue $151.1 M $127.3 M $222.6 M


Real-Time Hourly Inter-Regional Flows

Summer 2020


Trapped MW in MISO South

Average, Hours Ending 15-17


Wind Output in Real-Time

Daily Range and Average

0

5,000

10,000

15,000

20,000

1-7 8-14 15-21 22-31 1-7 8-14 15-21 22-31 1-7 8-14 15-21 22-31

Jun 2020 Jul 2020 Aug 2020

MW

Max 60-Minute Decrease: 3,316 MW

Max 60-Minute Increase: 2,862 MW

Max Actual Output (MW) 16,080

Avg Actual Output (MW) 6,180

Avg. Wind Scheduled DA 83%


Day-Ahead and Real-Time Price Convergence

Summer 2019-2020

-$10

$0

$10

$20

$30

$40

$50

DARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDART

19 20 J J A S O N D J F M A M J J A

Summer 2019 2020

$/M

Wh

Average Price Difference

Absolute Difference

RT RSG Rate DA RSG Rate

Average RT Price Average DA Price

Indiana Hub 1 4 1 -1 4 -2 -4 -2 3 0 6 7 -3 0 8 -2 5Michigan Hub 0 0 1 -5 4 1 -4 -1 3 -1 6 7 -6 4 3 -5 3Minnesota Hub 1 -2 2 -3 6 1 0 2 5 -4 7 3 1 0 -5 -3 1WUMS Area -4 -1 -6 -11 6 4 -3 5 5 -1 3 6 2 1 1 -3 -2Arkansas Hub 3 0 8 -1 2 -2 -4 -3 4 1 4 6 5 6 6 -7 2Texas Hub -4 -12 1 5 -18 1 -16 -1 4 1 6 10 5 13 7 2 -44Louisiana Hub 5 2 10 0 6 2 1 -3 2 1 -2 12 4 5 6 1 0

Average DA-RT Price Difference Including RSG (% of Real-Time Price)


Day-Ahead Peak Hour Load Scheduling

Summer 2019-2020

80%

84%

88%

92%

96%

100%

104%

18 19 20 A M J J A S O N D J F M A M J J A

Summer 2019 2020

Sh

are

of

Act

ua

l L

oa

d

Net Virtual Supply Net Virtual Load

Higher DA NSI Lower DA NSI

Price-Based Load Fixed Load

Share of Actual Load (%)

All Hours

Peak Hours

Midwest

Peak Hours

South

99.5

99.8

100.9

98.5

99.0

99.6

99.9

100.1

100.0

98.9

98.5

98.2

99.5

99.0

98.9

99.0

99.5

100.4

101.5

101.0

98.1

99.0

99.5

97.4

98.8

98.8

98.6

99.7

99.9

99.0

98.2

98.5

99.6

98.9

100.2

98.2

98.4

99.9

99.8

98.9

100.6

100.0

101.7

99.9

98.5

100.9

100.2

98.9

100.2

100.6

100.7

99.1

99.2

98.5

98.2

101.0

101.5

101.2

101.8

102.0


Peaking Resource Dispatch

Summer 2019-2020

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

400

800

1,200

1,600

2,000

2,400

2,800

3,200

3,600

4,000

4,400


2019 2020

In-M

erit

MW

%

Av

era

ge

Ho

url

y M

W

Local Voltage Real-Time Congestion

Real-Time Capacity Day-Ahead

Percent In-Merit

Mo. Avg.


Day-Ahead RSG Payments

Summer 2019-2020

$0

$2

$4

$6

$8

$10

$12

$14


Mo. Avg. 2019 2020

RS

G P

ay

men

ts (

$ M

illi

on

s)

Midwest South Total

Fuel-Adjusted RSG: Capacity $2.37 $2.32 $4.69

Fuel-Adjusted RSG: VLR $0.04 $2.91 $2.95

Total Nominal RSG $1.83 $3.86 $5.69

RSG Mitigation $0.32

Sum of Summer 2020 ($ Millions)


Real-Time RSG Payments

Summer 2019-2020

$0

$2

$4

$6

$8

$10

$12

$14


Mo. Avg. 2019 2020

RS

G P

ay

men

ts (

$ M

illi

on

s)

Sum of Summer 2020 ($ Millions) Midwest South Total

Fuel-Adjusted RSG: VLR $0.03 $0.70 $0.73

Fuel-Adjusted RSG: Congestion $2.46 $0.76 $3.23

Fuel-Adjusted RSG: RDT $0.12 $0.72 $0.84

Fuel-Adjusted RSG: Capacity $13.51 $3.25 $16.76

Total Nominal RSG $12.36 $4.29 $16.65

RSG Mitigation $0.25


Price Volatility Make Whole Payments

Summer 2019-2020

$0

$2

$4

$6

$8

$10

$0

$2

$4

$6

$8

$10


Summer 2019 2020

Vo

lati

lity

(Av

era

ge

Inte

rv

al

Pri

ce C

ha

ng

e)

Up

lift

Pa

ym

ents

($

Mil

lio

ns)

DAMAP (Midwest) RTORSGP (Midwest)

DAMAP (South) RTORSGP (South)

LMP Volatility SMP Volatility


Virtual Load and Supply

Summer 2019-2020

-40,000

-30,000

-20,000

-10,000

0

10,000

20,000

30,000

40,000

181920 J J A S O N D J F M A M J J A 181920 J J A S O N D J F M A M J J A

Summer 2019 2020 Summer 2019 2020

Midwest South

Av

era

ge

Ho

url

y V

olu

me

(MW

)

← S

up

ply

Dem

an

d →

Uncleared

Cleared, Price Sensitive

Cleared, Price Insensitive

Cleared, Screened Transactions


Virtual Load and Supply by Participant Type

Summer 2019-2020

-40,000

-30,000

-20,000

-10,000

0

10,000

20,000

30,000

40,000

50,000

181920 J J A S O N D J F M A M J J A 181920 J J A S O N D J F M A M J J A

Summer 2019 2020 Summer 2019 2020

Financial-Only Participants Generators / LSEs

Av

era

ge

Ho

url

y V

olu

me

(MW

)

← S

up

ply

Dem

an

d →

Uncleared

Cleared, Price Sensitive

Cleared, Price Insensitive

Cleared, Screened Transactions


Virtual Profitability

Summer 2019-2020

-$3

$0

$3

$6

$9

$12$0

$10

$20

$30

$40


Summer 2019 2020

Pro

fita

bil

ity P

er M

W

Pro

fits

($

Mil

lion

s)

Supply Demand Gross

Percent Screened

Supply 0.3 0.2 0.4 0.2 0.3 0.2 0.4 0.3 0.3 0.1 0.2 0.1 0.2 0.2 0.4 0.5 0.3 0.3

Demand 1.9 1.0 1.3 1.4 1.1 0.5 1.6 1.1 0.9 0.7 0.4 0.5 0.5 0.4 0.9 1.6 1.2 1.1

Total 1.1 0.6 0.9 0.8 0.7 0.3 1.0 0.7 0.6 0.4 0.3 0.3 0.4 0.3 0.6 1.0 0.8 0.7


Day-Ahead and Real-Time Ramp Up Price

2019-2020

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

$1.00

M J J A S O N D J F M A M J J A

2019 2020

Ra

mp

Up

MC

P (

$ p

er M

Wh

)

Average RT Ramp Up MCP

Average DA Ramp Up MCP


Evaluation of ELMP Assumptions

Summer 2020

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

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

SM

P I

ncr

ease

fro

m E

x-A

nte

($/M

Wh

)

Hour Ending

Alternative ELMP MethodsAvg. Price Increase

($/MWh)

% of Fast-Start

Peaker Eligible

% of Intervals

Affected

Elmp Phase II $0.09 0.9% 2.3%

Elmp Phase III (Currrent) $0.66 21.6% 28.8%

Elmp Phase III Without Ramp Limit $1.63 37.0% 43.6%

* Exclude Shortage Intervals


Coordinated Transaction Scheduling (CTS)

2019-2020

(150)

(100)

(50)

-

50

100

150

200

250

300

350

F M A M J J A S O N D J F M A M J J A

2019 2020

Qu

an

tity

(M

W)

MISO Reservation Charges Imports Exports

Per Offered MWh $0.28 $0.73

Per Cleared MWh $0.79 $2.66

Imp

ort

sE

xp

ort

s


Monthly Output Gap

Summer 2019-2020

0.0%

0.1%

0.2%

0.3%

0.4%

0

50

100

150

200

250


Mo. Avg 2019 2020

Sh

are

of

Act

ua

l L

oa

d

Ou

tpu

t G

ap

(M

W)

Low Threshold

High Threshold

Share of Actual Load

Low Threshold Results by Unit Status (MW)

High Threshold Results by Unit Status (MW)

Offline 8 8 22 8 9 9 10 15 10 5 0 0 0 0 3 12 36 18

Online 67 37 166 33 42 36 45 54 25 25 27 23 36 84 42 163 180 155

Offline 7 8 19 7 9 8 8 11 10 5 0 0 0 0 3 11 31 16

Online 14 8 29 9 8 7 10 12 4 4 5 3 11 33 15 50 21 17


Day-Ahead And Real-Time Energy Mitigation

2019-2020

0

240

480

720

960

1200

1440

1680

1920

2160

2400

0

5

10

15

20

25

30

35

40

45

50

19 20 J J A S O N D J F M A M J J A 19 20 J J A S O N D J F M A M J J A

Mo.

Total

2019 2020 2019 2020

BCA NCA

MW

Mit

iga

ted

Ho

urs

DA Hours Mitigated, NCA

RT Hours Mitigated, NCA

DA Hours Mitigated, BCA

RT Hours Mitigated, BCA

Combined MW Mitigated


Day-Ahead and Real-Time RSG Mitigation

Summer 2019-2020

0

30

60

90

120

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000


Mo. Avg. 2019 2020

Mit

iga

ted

Un

it-D

ay

s

RS

G M

itig

ati

on

Do

lla

rs

DA RSG Mitigated

RT RSG Mitigated

Combined Unit-Days


• AAR Ambient-Adjusted Ratings

• AMP Automated Mitigation Procedures

• BCA Broad Constrained Area

• CDD Cooling Degree Days

• CMC Constraint Management Charge

• CTS Coordinated Transaction Scheduling

• DAMAP Day-Ahead Margin Assurance

Payment

• DDC Day-Ahead Deviation & Headroom

Charge

• DIR Dispatchable Intermittent Resource

• HDD Heating Degree Days

• ELMP Extended Locational Marginal Price

• JCM Joint and Common Market Initiative

• JOA Joint Operating Agreement

• LAC Look-Ahead Commitment

• LSE Load-Serving Entities

• M2M Market-to-Market

• MSC MISO Market Subcommittee

• NCA Narrow Constrained Area

List of Acronyms

• ORDC Operating Reserve Demand

Curve

• PITT Pseudo-Tie Issues Task Team

• PRA Planning Resource Auction

• PVMWP Price Volatility Make Whole

Payment

• RAC Resource Adequacy Construct

• RDT Regional Directional Transfer

• RSG Revenue Sufficiency Guarantee

• RTORSGPReal-Time Offer Revenue

Sufficiency Guarantee Payment

• STE Short-Term Emergency

• SMP System Marginal Price

• SOM State of the Market

• TLR Transmission Loading Relief

• TCDC Transmission Constraint

Demand Curve

• VLR Voltage and Local Reliability

• WUMS Wisconsin Upper Michigan

System

Documents

IMM Quarterly Report: Summer 2020 · • MISO’s summer peak load slightly above 117 GW occurred on August 24. ... We have recommended VOLL for shortage pricing of $23,000 so we