imm quarterly report: summer 2020 · • miso’s summer peak load slightly above 117 gw occurred...
TRANSCRIPT
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 $2 per MMBTU this quarter, rising in August.
• MISO’s summer peak load slightly above 117 GW occurred on August 24.
✓ Average load remained consistent with prior summers, as COVID-related impacts diminished and were offset by hotter temperatures.
• MISO experienced several significant events this summer.
✓ In Michigan, MISO declared a Local Transmission Emergency in June and a Transmission System Emergency in July, resulting in very high congestion.
✓ MISO experienced a week of hot temperatures in early July and on July 7, it declared a Maximum Generation Event in the Midwest region.
✓ In Western WOTAB on Aug 27, MISO declared an emergency and cut load.
– Prices were finalized a week after the event and set at the VOLL.
✓ MISO also declared on Local Transmission Emergency in Texas on August 28 that was caused by storm-related transmission outages.
Highlights and Findings: Summer 2020
-3-© 2020 Potomac Economics
Quarterly Summary
Value
Prior
Qtr.
Prior
Year Value
Prior
Qtr.
Prior
Year
RT Energy Prices ($/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.
-4-© 2020 Potomac Economics
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
-5-© 2020 Potomac Economics
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.
Highlights for Summer 2020
-6-© 2020 Potomac Economics
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.
Highlights for Summer 2020
-7-© 2020 Potomac Economics
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.
Highlights for Summer 2020
-8-© 2020 Potomac Economics
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.
Highlights for Summer 2020
-9-© 2020 Potomac Economics
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.
Highlights for Summer 2020
-10-© 2020 Potomac Economics
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.
Highlights for Summer 2020
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
-11-© 2020 Potomac Economics
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.
Highlights for Summer 2020
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
-12-© 2020 Potomac Economics
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
Highlights for Summer 2020
-13-© 2020 Potomac Economics
• 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
-14-© 2020 Potomac Economics
• 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
-15-© 2020 Potomac Economics
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
-16-© 2020 Potomac Economics
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
-17-© 2020 Potomac Economics
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
-18-© 2020 Potomac Economics
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
-19-© 2020 Potomac Economics
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
-20-© 2020 Potomac Economics
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
-21-© 2020 Potomac Economics
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
-22-© 2020 Potomac Economics
Hot Week in Early 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
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M
5:0
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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
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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
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M
3:0
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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
-23-© 2020 Potomac Economics
Maximum Generation Event on July 7, 2020
Midwest Region
0
20,000
40,000
40,000
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70,000
80,000
90,000
100,000
12
:00 A
M1
2:3
0 A
M1
:00
AM
1:3
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M2
:00
AM
2:3
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M3
:00
AM
3:3
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M4
:00
AM
4:3
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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
-24-© 2020 Potomac Economics
Peak Hour Midwest Capacity Availability
Midwest Region - July 7, Hour 16
-25-© 2020 Potomac Economics
Uplift by Commitment Time
Hot Week in Early July
$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
-26-© 2020 Potomac Economics
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).
-27-© 2020 Potomac Economics
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)
-28-© 2020 Potomac Economics
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)
-29-© 2020 Potomac Economics
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
-30-© 2020 Potomac Economics
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
-31-© 2020 Potomac Economics
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
-32-© 2020 Potomac Economics
Real-Time Hourly Inter-Regional Flows
Summer 2020
-33-© 2020 Potomac Economics
Trapped MW in MISO South
Average, Hours Ending 15-17
-34-© 2020 Potomac Economics
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%
-35-© 2020 Potomac Economics
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)
-36-© 2020 Potomac Economics
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
-37-© 2020 Potomac Economics
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
18 19 20 J J A S O N D J F M A M J J A
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.
-38-© 2020 Potomac Economics
Day-Ahead RSG Payments
Summer 2019-2020
$0
$2
$4
$6
$8
$10
$12
$14
18 19 20 J J A S O N D J F M A M J J A
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)
-39-© 2020 Potomac Economics
Real-Time RSG Payments
Summer 2019-2020
$0
$2
$4
$6
$8
$10
$12
$14
18 19 20 J J A S O N D J F M A M J J A
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
-40-© 2020 Potomac Economics
Price Volatility Make Whole Payments
Summer 2019-2020
$0
$2
$4
$6
$8
$10
$0
$2
$4
$6
$8
$10
18 19 20 J J A S O N D J F M A M J J A
Summer 2019 2020
Vo
lati
lity
(Av
era
ge
Inte
rv
al
Pri
ce C
ha
ng
e)
Up
lift
Pa
ym
ents
($
Mil
lio
ns)
DAMAP (Midwest) RTORSGP (Midwest)
DAMAP (South) RTORSGP (South)
LMP Volatility SMP Volatility
-41-© 2020 Potomac Economics
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
-42-© 2020 Potomac Economics
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
-43-© 2020 Potomac Economics
Virtual Profitability
Summer 2019-2020
-$3
$0
$3
$6
$9
$12$0
$10
$20
$30
$40
18 19 20 J J A S O N D J F M A M J J A
Summer 2019 2020
Pro
fita
bil
ity P
er M
W
Pro
fits
($
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
-44-© 2020 Potomac Economics
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
-45-© 2020 Potomac Economics
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
-46-© 2020 Potomac Economics
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
-47-© 2020 Potomac Economics
Monthly Output Gap
Summer 2019-2020
0.0%
0.1%
0.2%
0.3%
0.4%
0
50
100
150
200
250
18 19 20 J J A S O N D J F M A M J J A
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
-48-© 2020 Potomac Economics
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
-49-© 2020 Potomac Economics
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
18 19 20 J J A S O N D J F M A M J J A
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
-50-© 2020 Potomac Economics
• 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