imm quarterly report: winter 2018 - potomaceconomics.com€¦ · imm quarterly report: winter 2018...

IMM Quarterly Report:

Winter 2018

MISO Independent Market Monitor

David Patton, Ph.D.

Potomac Economics

March 27, 2018

-2-© 2018 Potomac Economics

• The MISO markets performed competitively this winter.

✓ Natural gas prices fell by 6 percent over last year, but energy prices increased by 8 percent over the same period due to January weather-related events.

✓ Market power mitigation was infrequent and offers were competitive.

• In January, extremely cold temperatures throughout the footprint affected gas prices, generation outages and performance, and energy prices.

✓ Significant fuel price volatility in late December and early January contributed to high congestion and price volatility.

• On January 17 and 18, MISO declared Maximum Generation Events and took a number of emergency actions in the South.

✓ Temperature-related forced outages contributed to tight conditions on multiple days.

✓ LMRs were scheduled and deployed on both days and MISO took a number of other emergency actions on January 17.

✓ Reliability was maintained, but prices did not efficiently reflect conditions.

• A new wind output record of 15.0 GW was set on January 17.

• Transmission congestion was significantly higher this winter than last year.

Highlights and Findings: Winter 2018


Quarterly Summary

Value

Prior

Qtr.

Prior

Year Value

Prior

Qtr.

Prior

Year

RT Energy Prices ($/MWh) $31.13 4% 8% FTR Funding (%) 101% 100% 99%

Fuel Prices ($/MMBtu) Wind Output (MW/hr) 7,217 14% 5%

Natural Gas - Chicago $3.08 7% -6% Guarantee Payments ($M)4

Natural Gas - Henry Hub $3.06 4% -6% Real-Time RSG $17.7 -25% 50%

Western Coal $0.70 4% 4% Day-Ahead RSG $11.1 12% -19%

Eastern Coal $1.51 1% -2% Day-Ahead Margin Assurance $13.7 16% 27%

Load (GW)2 Real-Time Offer Rev. Sufficiency $1.0 -43% -21%

Average Load 79.4 9% 5% Price Convergence5

Peak Load 106.1 -8% 4% Market-wide DA Premium 2.4% -3.0% 0.2%

% Scheduled DA (Peak Hour) 98.7% 98.4% 99.0% Virtual Trading

Transmission Congestion ($M) Cleared Quantity (MW/hr) 15,519 4% 30%

Real-Time Congestion Value $384.4 -15% 29% % Price Insensitive 35% 30% 30%

Day-Ahead Congestion Revenue $231.4 14% 56% % Screened for Review 1% 1% 1%

Balancing Congestion Revenue3 $.6 $12.8 $11.4 Profitability ($/MW) $1.32 $0.83 $0.55

Ancillary Service Prices ($/MWh) Dispatch of Peaking Units (MW/hr) 831 1023 444

Regulation $9.98 -1% 5% Output Gap- Low Thresh. (MW/hr) 82 95 92

Spinning Reserves $2.69 -7% 35% Other:

Supplemental Reserves $1.32 80% 80%

Key: Expected Notes:

Monitor/Discuss

Concern

4. Includes effects of market power mitigation.

Change1

Change1

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

2. Comparisons adjusted for any change in membership.

5. Values include allocation of RSG.

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


Winter Peak: Late Dec ‘17 / Early Jan ‘18 (Slides 12, 13, 20, 21, 22)

• Gas prices rose 15 percent in January from the prior year, contributing to a 40 percent increase in energy prices.

• Extremely cold weather throughout the footprint from January 1 to 4 led to:

✓ MISO-wide Cold Weather Alerts and Conservative Operations ending Jan 6.

✓ Winter load peaked on January 2 at 104.7 GW, but was lower than the all-time winter peak load of 109.3 GW during the 2014 Polar Vortex.

✓ Fuel-related generation outages and more than 4 GW of generation that could only be used in an emergency contributed to tight operating conditions on several days.

– 14 intervals of operating reserve shortages occurred with average prices of $501/MWh.

✓ Multiple gas pipeline restrictions and high gas prices occurred.

– Dual-fuel capable units switched to burn oil that was cheaper than gas.

• Cold weather in late December also led to gas price volatility. The Ventura hub price was as high as $67.50 on three days and affected many units.

• We consulted with multiple participants on generation fuel costs for references and no inappropriate mitigation occurred.

Highlights for Winter 2018


Winter Peak: Jan 17th-18th in MISO South (Slides 12, 14, 15, 16, 17, 18)

• Unusually cold weather in the South on January 17 and 18 led to a record winter peak in the South of 32.1 GW on January 17 and emergency events.

• Conditions were extremely tight on January 17 from 6 AM to 1 PM:

✓ MISO’s load forecast in the early morning showed a significant capacity deficiency by 9 AM, prompting MISO to declare a Max Gen Alert starting 5 AM .

✓ The actual load was well below the forecast by the peak hours (7 to 9 AM) due to voluntary load curtailments and the initial response from LMRs called at 6 AM.

✓ However, forced outages rose from 5 GW at midnight to almost 7.5 GW by 8:30.

✓ MISO relaxed some of its transmission limits in the South, raising them by roughly 25 percent to increase access to generation.

✓ Because load exceeded supply, MISO exceeded the RDT limit for roughly an hour from 6:45 AM to 7:45 AM, by almost 1000 MW at 7:25 AM.

✓ MISO scheduled emergency transactions beginning at 7:30 AM that exceeded 1000 MW by 9 AM, allowing it to reduce the RDT flows to below the limit.

• MISO declared an emergency for the evening peak and for the morning of the 18th, but conditions were not as tight because some units returned from outage.

• Given the supply and demand conditions, all of MISO’s actions were necessary to keep the lights on in the South.



Winter Peak: Jan 17th-18th in MISO South (Slides 12, 14, 15, 16, 17, 18)

• Day-ahead congestion was much higher than real-time congestion costs.

✓ Emergency actions taken on both days resulted in lower real-time congestion.

✓ Louisiana Hub day-ahead premium exceeded $1,100 for one hour on Jan 18.

• Findings regarding LMRs:

✓ The LMRs were not obligated to be available (only required in the summer).

✓ Long notification times limit LMRs’ value – schedules were low on the 17th

in the morning peak. MISO declared the event early on Jan 18 to secure them.

✓ It is difficult to tell from observing the load the extent of the LMR response.

✓ This event may underscore the value of reconsidering how MISO quantifies the capacity credit for LMRs in the PRA.

• Findings regarding prices during the event on the 17th:

✓ Prices were high when the RDT was violated due to the RDT demand curve.

✓ Emergency procedures raised prices slightly, but much lower than optimal:

– ELMP did not properly account for RDT flows.

– The emergency price floor set by a unit offer can be too low or too high.

✓ Adding the regional reserve requirements and pricing any shortages that occur will lead to fully efficient prices.



High Congestion (Slides 10, 23, 24, 25, 26)

• Day-ahead and real-time quarterly congestion costs increased 56 and 29 percent, respectively, over last year.

✓ High gas volatility days early in the month, record-high wind production, and emergency conditions the South in January were contributing factors.

✓ More than one quarter of all day-ahead congestion occurred on January 17 and January 18.

• In January, MISO incurred $162 million in real-time congestion in the Midwest and $64.5 million in the South.

• More than 40 percent of real-time congestion was attributable to market-to-market constraints.

✓ One constraint impacted by a PJM pseudo-tied unit contributed to $36 million in congestion in the quarter, and PJM paid MISO $9.6 million.

✓ Wind units in PJM had the majority of relief on a constraint that contributed to $29 million in real-time congestion (which is difficult to manage).



• We made two new referrals and responded to FERC questions related to prior referrals and continued to meet with FERC on a weekly basis.

✓ A participant provided false information in a Reference Price Consultation.

✓ We also referred a matter related to PJM’s failure to perform CMP Study 1 and MISO is evaluating impacts for possible resettlement.

✓ We responded to several data requests related to prior referrals.

✓ We made several notifications of other potential Tariff violations.

• We participated in the following FERC dockets.

✓ We filed a protest related to MISO’s refiling of its capacity market in an attempt to remedy the design flaw that causes inefficiently low prices.

– FERC affirmed the design flaw, but the Order ignores the evidence we and others filed.

✓ We assisted MISO in the Order 831 Compliance filing (increasing the Offer Cap), and a modification to the Resource Adequacy Construct to include external resource zones in the PRA.

✓ We submitted comments in the Fast-Start Pricing dockets in NY and PJM.

Submittals to External Entities and Other Issues


• We participated in a number of stakeholder discussions and working groups.

✓ At the MSC and at the ERSC, we discussed concerns with the current RDT commitment tool and the need for improvements to reduce inefficient commitments.

✓ We continued to work with MISO and stakeholders on proposed improvements to the Uninstructed Deviation Thresholds (SOM 2012-2) and improved incentives for PVWMP (SOM 2016-5).

✓ In February, we presented at the RASC meeting to prepare stakeholders for the upcoming PRA.

✓ We participated in the February PJM-MISO JCM Meeting.

Submittals to External Entities and Other Issues


Day-Ahead Average Monthly Hub Prices

Winter 2016 – 2018

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$0

$10

$20

$30

$40

$50

$60

$70

Dec Jan Feb Dec Jan Feb Dec Jan Feb

Winter 2016 Winter 2017 Winter 2018

Na

tura

l G

as

Pri

ce ($

/MM

Btu

)

$/M

Wh

Mean Gas Price Texas Hub

Arkansas Hub Louisiana Hub

Minnesota Hub Indiana Hub

Michigan Hub


All-In Price

Winter 2016 – 2018

$0

$2

$4

$6

$8

$10

$0

$10

$20

$30

$40

$50

16 17 18 J F M A M J J A S O N D J F M A M J J A S O N D J F

Mo. Avg. 2016 2017 2018

Na

tura

l G

as

Pri

ce ($

/MM

Btu

)

All

-In

Pri

ce ($

/MW

h)

Capacity Ancillary Services

Uplift Energy (Shortage)

Energy (Non-shortage) Natural Gas Price


Average Temperatures on January Cold Days

Hist.

Avg.* 1 2 3 4 5 16 17 18 19

Midwest

Minneapolis 14.2 -7.2 4.1 3.1 -1.4 -4.0 1.7 14.4 30.7 35.3

Milwaukee 21.8 -1.1 4.6 12.6 5.9 5.1 20.5 15.9 26.0 35.2

Detroit 25.9 8.4 6.7 10.8 8.7 1.5 13.1 12.7 20.7 29.7

Indianapolis 27.2 -3.7 -1.4 12.8 4.6 0.7 2.3 8.3 19.9 30.1

South

Little Rock 38.9 15.8 16.7 24.0 24.9 29.4 17.0 14.7 24.0 34.3

New Orleans 53.7 31.3 31.5 38.2 38.2 39.7 37.3 27.7 33.4 43.6

Cold Weather Alert (MISO)

Conservative Ops in MISO (Jan 2-5) and South (Jan 16,19)

Max Gen Event in South

* Historical Avg. is average of those days' average temperature from 2008-2017.

January


Cold Weather Alerts and Conservative Ops

January 1 - 4

80,000

90,000

100,000

110,000$0

$120

$240

$360

Jan. 1 2 3 4

Lo

ad

(M

W)

Pri

ce ($

/MW

h)

Conservative OPS Cold Weather Alert Actual Load

January 1 January 2 January 3 January 4

DA SMP

RT SMP

DA F'cast Load

DA Sched. Load


Conservative Ops and Max Generation Event in

MISO South January 17 & 18

15,000

19,000

23,000

27,000

31,000

35,000$0

$200

$400

$600

$800

$1000

August 10 17 18 10

Lo

ad

(M

W)

Pri

ce ($

/MW

h)

MaxGen Event (South) Conservative Ops (South)

January 16 January 17 January 18 January 19

DA Load Weighted Price

RT Load Weighted Price

DA F'cast Load

DA Sched. Load

Actual Load


MISO South Generation and Load

January 17

0

500

1,000

22,000

24,000

26,000

28,000

30,000

32,000

34,000

36,000

38,000

40,000

42,000

44,000

46,000

48,000

50,000

52,000

3 5 7 9 11 13 15 17 19 21 23

MW

MW

Jan. 17

Total Supply (incl. Imports & RDT)

Total Generation + RDT

Available Supply

Load

Scheduled LMR

Cancelled Scheduled LMR

Planned Outages

Forced Outages

Derates

Supply w/out

Emer. Purchases

7300 MW4100 MW

7000 MW

9200 MW

Generation

lost to

Outages

and Derates



January 17 Maximum Generation Event

0

200

400

22,000

24,000

26,000

28,000

30,000

32,000

34,000

36,000

5 6 7 8 9 10 11 12 13

MW

MW

January 17

Available

Supply

LoadSupply w/out

Emer. Purchases

Scheduled LMR

MTLF



January 18, 2018

0

500

1,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

32,000

34,000

36,000

38,000

40,000

42,000

44,000

46,000

48,000

50,000

52,000

0 3 6 9 12 15 18 21

MW

MW

Jan. 18

Load

Total Supply (incl. Imports & RDT)

Available Supply

Scheduled LMR

Cancelled Scheduled LMR

Planned Outages

Forced Outages

Derates

Total Generation + RDT


Pricing on January 17 During

Maximum Generation Event

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

6:00 6:30 7:00 7:30 8:00 8:30 9:00 9:30 10:00 10:30 11:00 11:30 12:00

Emergency PurchasesExceeded

RDT

Efficient LMP with Emergency and

Shortage Pricing (30 min reserves)

Correct Emergency

Pricing in ELMP

Actual LMP Ex Ante LMP


Monthly Average Ancillary Service Prices

Winter 2017 – 2018

-$2

$0

$2

$4

$6

$8

$10

$12

$14

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

2016 2017 2018 2016 2017 2018 2016 2017 2018

Regulation Spinning Reserve Supplemental Reserve

$/M

Wh

Regulation Price (exclude shortages)

MCP Impact from Reg Shortages

Spinning Reserve Price (exclude shortages)

MCP Impact from Spin Shortages

Supp Reserve Price (exclude shortages)

MCP Impact from OR Shortages

Day-Ahead Premium

Winter Average of Five Years


MISO Fuel Prices

2016 – 2018

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

$5.0

$5.5

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

16 17 18

$/M

MB

tu

2016 2017 2018

2016 2017 2018

IB Coal $1.36 $1.54 $1.51

PRB Coal $0.55 $0.67 $0.70

Winter Average

9.01

2016 2017 2018

Chicago NG $2.10 $3.26 $3.08

Henry NG $2.04 $3.25 $3.06

Winter Average


MISO Fuel Prices

Winter 2018

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

$16.0

1 5 9 13 17 21 25 29 1 5 9 13 17 21 25 29 1 5 9 13 17 21 25

December 2017 January 2018 February 2018

$/M

MB

tu Oil

IB Coal

PRB Coal

Ventura Gas

Henry Hub Gas

Chicago Gate Gas

$68


Load and Weather Patterns

Fall 2016 – 2018

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

Minneapolis. The South region includes Little Rock and New Orleans.

60,000

70,000

80,000

90,000

100,000

110,000

120,000

130,000

0

300

600

900

1,200

1,500

1,800

16 17 18 15 16 17 16 17 18 16 17 18

Monthly Avg. Dec Jan Feb

Lo

ad

(M

W)

Ad

just

ed

Deg

ree D

ays

CDDs

HDDs

Average Load

Historical Avg.

Peak Load


Day-Ahead Congestion, Balancing Congestion

and FTR Underfunding, 2016 – 2018

-$15M

$0M

$15M

$0 M

$25 M

$50 M

$75 M

$100 M

$125 M

$150 M

$175 M

$200 M


2016 2017 2018

2017 2018

Balancing Congestion Revenue ($11.4 M) $0.6 M

DA Congestion Revenues $148.5 M $231.4 M

FTR Surplus (Shortfall) ($3.0 M) $6.6 M

FTR Funding (%) 99.1% 101.3%

Winter Totals


Value of Real-Time Congestion

Winter 2017 – 2018

$0

$50

$100

$150

$200

$250

$300

16 17 18 D J F M A M J J A S O N D J F

Mo. Avg. 16 2017 2018

Co

ng

est

ion

Va

lue ($

Mil

lio

ns)

Totals Win. 17 Fall 17 Win. 18

Midwest 201.4 M 370.3 M 292.8 M

Transfer Constraints 3.4 M 7.0 M 10.4 M

South 92.1 M 76.0 M 81.3 M

Total RT Value 296.9 M 453.3 M 384.4 M

DA Congestion Revenue 148.5 M 203.4 M 231.4 M


Market-to-Market Testing and Activation Delay

Congestion Costs: 2017 - 2018

$0

$20

$40

$60

$80

$100

$120

$140

$160C

onges

tio

n V

alue

($ M

illio

n)

Winter

2017

Spring

2017

Summer

2017

Fall

2017

Winter

2018

Never classified as M2M (PJM) $37.1 $29.6 $7.1 $73.3 $20.3

Never classified as M2M (SPP) $11.1 $57.8 $22.5 $30.3 $6.5

M2M Testing Delay (PJM) $8.8 $15.2 $15.8 $19.9 $4.8

M2M Testing Delay (SPP) $1.9 $2.4 $1.3 $5.1 $0.1

Congestion ($ Million)

Categories (NMRTO)


MISO Congestion Value and JOA Settlement

Constraints Impacted by Pseudo-Ties

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

1 2 3 4 1 2 3 4 1 2 3 4 1

2015 2016 2017 2018

Mill

ions

JOA Payment - Uplift

JOA Payment - Transfer

Real-Time Congestion

Period with New PJM Pseudo-Ties

Before Pseudo Ties $22.4 M

After Pseudo Ties $38.3 M

Percentage Increase 71%

Average Congestion Per Quarter


Real-Time Hourly Inter-Regional Flows

2017 - 2018

-4,000

-3,000

-2,000

-1,000

0

1,000

2,000

3,000

4,000

RD

T F

low

So

uth

to

No

rth

(M

W)

-3000 MW RDT Limit

2500 MW RDT Limit

M A M J J A S O N November December January February

Hourly Average

Daily Average

Monthly Average

Monthly Avg.


Wind Output in Real-Time and Day-Ahead

Monthly and Daily Average

-2,000

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

J F M A M J J A S O N D J F 1-7 8-14 15-21 22-31 1-7 8-14 15-21 22-31 1-7 8-14 15-2122-28

2017 2018 Dec. 2017 Jan. 2018 Feb. 2018

Monthly Average Daily Average

Qu

an

tity

(M

W)

Winter Avg. 2016 2017 2018

Net Virtual Supply 562 452 86

Day-Ahead Wind 5,094 5,951 6,042

Real-Time Wind 5,731 6,903 7,217


Day-Ahead and Real-Time Price Convergence

Winter 2017 – 2018

-$10

$0

$10

$20

$30

$40

$50

$60

DARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDARTDART

17 18 D J F M A M J J A S O N D J F

Mo. Avg. 2016 2017 2018

$/M

Wh

Average Price Difference

Absolute Difference

RT RSG Rate DA RSG Rate

Average RT Price Average DA Price

Indiana Hub 1 -3 1 0 1 -4 0 -3 5 -3 1 -16 3 2 4 -6 -8Michigan Hub 1 0 2 1 1 -6 -1 -1 0 -3 1 -11 -1 0 2 -2 1Minnesota Hub 0 -1 -6 3 3 -1 -5 1 5 -7 2 -7 -10 3 0 3 -6WUMS Area -3 0 -6 -1 -2 3 -1 3 3 -8 3 -11 0 0 2 2 -3Arkansas Hub 1 -2 0 1 3 -3 0 2 5 -7 2 -2 5 -3 1 -7 -1Texas Hub 1 -1 2 -2 3 -2 3 4 -1 -1 3 1 8 -6 4 -5 -1Louisiana Hub 1 -9 1 1 -2* 2 -4 3 -1 -9 -6 -1 7 -5 5 3* 3* Excluding Feb. 7, 2017 and Jan. 17-18, 2018.

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


Day-Ahead Peak Hour Load Scheduling

Winter 2017 – 2018

80%

84%

88%

92%

96%

100%

104%


Monthly Avg. 2016 2017 2018

Sh

are

of A

ctu

al

Lo

ad

Net Virtual Supply Net Virtual Load

Higher DA NSI Lower DA NSI

Price-Based Load Fixed Load

Share of Actual Load (%)

All Hours

Peak HoursMidwest

Peak HoursSouth

98.7

99.1

98.7

98.9

99.2

98.7

99.1

98.5

99.3

100.2

99.6

99.9

98.9

98.8

98.6

99.2

98.7

98.6

98.7

98.4

98.0

97.8

98.0

98.3

97.5

97.0

97.8

99.5

97.3

98.0

98.9

97.6

98.6

98.8

98.1

97.8

100.4

103.9

101.8

103.1

103.1

106.4

102.9

100.3

102.3

103.2

102.2

102.9

97.4

103.0

101.4

102.1

101.2

102.3


Virtual Load and Supply

Winter 2017 – 2018

32,000

28,000

24,000

20,000

16,000

12,000

8,000

4,000

0

4,000

8,000

12,000

16,000

20,000

24,000

28,000

16 17 18 D J F M A M J J A S O N D J F 16 17 18 D J F M A M J J A S O N D J F

Mo.

Avg.

16 2017 2018 Mo.

Avg.

16 2017 2018

Midwest South

Avera

ge H

ou

rly V

olu

me (

MW

)

← S

up

ply

D

em

an

d →

Uncleared

Cleared, Price Sensitive

Cleared, Price Insensitive

Cleared, Screened Transactions


Virtual Load and Supply by Participant Type

Winter 2017 – 2018

40,000

35,000

30,000

25,000

20,000

15,000

10,000

5,000

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

16 17 18 D J F M A M J J A S O N D J F 16 17 18 D J F M A M J J A S O N D J F

Mo.

Avg.

16 2017 2018 Mo.

Avg.

16 2017 2018

Financial-Only Participants Generators / LSEs

Avera

ge H

ou

rly V

olu

me (

MW

)

← S

up

ply

D

em

an

d →

Uncleared

Cleared, Price Sensitive

Cleared, Price Insensitive

Cleared, Screened Transactions


Virtual Profitability

January 1 - 20

-$4,000,000

$0

$4,000,000

$8,000,000

$12,000,000

To

tal P

rofi

ts

Date

Net MEC

Net MCC

Net MLC


Virtual Profitability

Winter 2017 – 2018

-$2

$0

$2

$4

-$5 M

$0 M

$5 M

$10 M

$15 M

$20 M

$25 M

$30 M

$35 M

$40 M

$45 M


Mo. Avg. 16 2017 2018

Pro

fits

per

MW

To

tal P

rofi

ts (

Mil

lio

ns)

Supply

Demand

Gross

Percent Screened

Demand 0.8 1.1 1.2 1.1 0.9 1.3 1.4 2.1 2.8 1.4 1.2 0.5 1.7 1.4 0.7 0.6 2.3 0.6

Supply 0.4 0.4 0.4 0.6 0.3 0.2 0.4 0.4 0.5 0.3 0.1 0.2 0.5 0.4 0.2 0.3 0.9 0.2

Total 0.6 0.7 0.8 0.8 0.6 0.7 0.9 1.2 1.6 0.8 0.7 0.3 1.0 0.9 0.5 0.4 1.6 0.4


Day-Ahead and Real-Time Ramp Up Price

2016 – 2018

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

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

2016 2017 2018

Ra

mp

Up

MC

P ($

per

MW

h)

Average RT Ramp Up MCP

Average DA Ramp Up MCP


Interface Pricing with PJM (Common Interface)

Winter 2018

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%S

ha

re o

f M

ark

et In

terv

als

Difference Relative to Ideal Price


Peaking Resource Dispatch

2016 – 2018

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


Mo. Avg. 16 2017 2018

In-M

eri

t M

W (

%)

Avera

ge H

ou

rly M

W

Real-Time Local Voltage Real-Time Congestion

Real-Time Capacity Committed Day-Ahead

Percent In-Merit


Day-Ahead RSG Payments

2016 – 2018

$0

$5

$10

$15

$20


Mo. Avg. 16 2017 2018

RS

G P

aym

en

ts ($

Mil

lio

ns)

Midwest South Total

Fuel-Adjusted RSG: VLR $1.18 $3.79 $4.97

Fuel-Adjusted RSG: Capacity $2.38 $2.01 $4.39

Total Nominal RSG $4.18 $6.88 $10.82

RSG Mitigation $0.24

Sum of 2018 Winter (Millions) Midwest South Total




RSG Mitigation $0.24

Sum of 2018 Winter (Millions)


Real-Time RSG Payments

2016 – 2018

$0

$5

$10

$15

$20


Mo. Avg. 16 2017 2018

RS

G P

aym

en

ts ($

Mil

lio

ns)



Fuel-Adjusted RSG: Congestion $0.64 $0.73 $1.36

Fuel-Adjusted RSG: RDT $0.30 $1.16 $1.46



RSG Mitigation $0.01 $0.07 $0.09



Fuel-Adjusted RSG: Congestion $0.64 $0.73 $1.36

Fuel-Adjusted RSG: RDT $0.30 $1.16 $1.46



RSG Mitigation $0.01 $0.07 $0.09


RDT Commitment RSG Payments

2016 – 2018

0

3

6

9

12

15

18

21

24

27

30

$0.0M

$1.0M

$2.0M

$3.0M

$4.0M

$5.0M

$6.0M

$7.0M


2016 2017 2018

# D

ays

Un

its

Co

mm

itte

d f

or

RD

T

RS

G ($

M)

RSG to South Units

RSG to Central/ North Units

# Days Units Committed for RDT


Price Volatility Make Whole Payments

2016 – 2018

$0

$3

$6

$9

$12

$0

$3

$6

$9

$12


Mo. Avg. 16 2017 2018

Vo

lati

lity

(Avera

ge I

nte

rva

l P

rice C

ha

ng

e)

Up

lift

Pa

ym

en

ts (

$ M

illi

on

s)

DAMAP (Midwest) RTORSGP (Midwest)

DAMAP (South) RTORSGP (South)

SMP Volatility LMP Volatility


Generation Outage Rates

2015–2016

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%


Winter 16 2017 2018

Sh

are

of

Ca

pa

cit

y

North South North South North South

Short-Term Unplanned Outages 4.1% 3.1% 4.7% 2.7% 4.1% 3.0%

Long-Term Unplanned Outages 3.9% 2.4% 5.1% 7.6% 5.5% 6.1%

Planned Outages 5.3% 6.7% 6.4% 7.8% 7.5% 10.6%

Total 13.2% 12.2% 16.2% 18.0% 17.1% 19.7%

2016 2017 2018Winter


Generation Outage Rates

South: 2015–2016

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%


Winter 16 2017 2018

Sh

are

of

Ca

pa

cit

y

Short-Term Unplanned Outages 3.1% 2.7% 3.0%

Long-Term Unplanned Outages 2.4% 7.6% 6.1%

Planned Outages 6.7% 7.8% 10.6%

Total 12.2% 18.0% 19.7%

Winter 2016 2017 2018


Monthly Output Gap

2016 – 2018

0.0%

0.1%

0.2%

0.3%

0.4%

0

25

50

75

100

125

150

175

200

225

250


Mo. Avg. 16 2017 2018

Sh

are

of A

ctu

al

Lo

ad

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

Online

Offline

Online

13 6 0 24 13 6 5 11 14 4 2 1 12 0 0 0 0 0

13 20 23 29 23 19 27 24 55 20 16 10 24 15 26 19 33 14

14 6 0 25 13 6 5 11 14 4 2 2 16 0 0 0 0 0

60 63 88 113 72 46 100 79 130 69 63 44 114 68 86 72 113 63


Day-Ahead And Real-Time Energy Mitigation

2017 – 2018

0

100

200

300

400

500

600

700

800

900

1000

0

20

40

60

80

100

120

140

160

180

200

161718 J F M A M J J A S O N D J F 161718 J F M A M J J A S O N D J F

Mo.

Total

2017 2018 Mo.

Total

2017 2018

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

2016 – 2018

0

30

60

90

120

$

$200

$400

$600

$800

$1000


Mo. Avg. 16 2017 2018

Mit

iga

ted

Un

it-D

ays

RS

G M

itig

ati

on

Do

lla

rs (T

ho

usa

nd

s) DA RSG Mitigated

RT RSG Mitigated

Combined Unit-Days


• AMP Automated Mitigation Procedures

• BCA Broad Constrained Area

• CDD Cooling Degree Days

• CMC Constraint Management Charge

• DAMAP Day-Ahead Margin Assurance

Payment

• DDC Day-Ahead Deviation & Headroom

Charge

• DIR Dispatchable Intermittent Resource

• HDD Heating Degree Days

• ELMP Extended Locational Marginal Price

• JCM Joint and Common Market Initiative

• JOA Joint Operating Agreement

• LAC Look-Ahead Commitment

• LSE Load-Serving Entities

• M2M Market-to-Market

• MSC MISO Market Subcommittee

• NCA Narrow Constrained Area

• ORDC Operating Reserve Demand Curve

List of Acronyms

• PITT Pseudo-Tie Issues Task Team

• PRA Planning Resource Auction

• PVMWP Price Volatility Make Whole

Payment

• RAC Resource Adequacy Construct

• RDT Regional Directional Transfer

• RSG Revenue Sufficiency Guarantee

• RTORSGPReal-Time Offer Revenue

Sufficiency Guarantee Payment

• SMP System Marginal Price

• SOM State of the Market

• TLR Transmission Line Loading

• Relief

• TCDC Transmission Constraint

Demand Curve

• VLR Voltage and Local Reliability

• WUMS Wisconsin Upper Michigan

System

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