MISO Independent Market Monitor

David B. Patton, Ph.D.

Potomac Economics

September 23, 2015

IMM Quarterly Report: Summer 2015

June – August

Quarterly Summary

- 2 -

Value

Prior

Qtr.

Prior

Year Value

Prior

Qtr.

Prior

Year

RT Energy Prices ($/MWh) $28.78 6% -17% FTR Funding (%) 102% 103% 98%

Fuel Prices ($/MMBtu) Wind Output (MW/hr) 2,931 -44% 7%

Natural Gas - Chicago $2.80 1% -34% Guarantee Payments ($M)4

Natural Gas - Henry Hub $2.78 2% -33% Real-Time RSG $20.2 60% 81%

Western Coal $0.58 0% -16% Day-Ahead RSG $21.1 -18% -42%

Eastern Coal $1.52 -7% -20% Day-Ahead Margin Assurance $7.9 -16% -44%

Load (GW)2 Real-Time Offer Rev. Sufficiency $2.3 -31% -54%

Average Load 84.1 19% 2% Price Convergence5

Peak Load 120.3 23% 4% Market-wide DA Premium 0.4% -0.4% 3.4%

% Scheduled DA (Peak Hour) 98.2% 99.2% 100.4% Virtual Trading

Transmission Congestion ($M) Cleared Quantity (MW/hr) 9,556 -4% 36%

Real-Time Congestion Value $342.2 -6% 3% % Price Insensitive 34% 36% 44%

Day-Ahead Congestion Revenue $196.3 -10% -7% % Screened for Review 1% 1% 2%

Balancing Congestion Revenue3 -$3.6 -$5.0 -$5.4 Profitability ($/MW) $0.87 $0.82 $0.22

Ancillary Service Prices ($/MWh) Dispatch of Peaking Units (MW/hr) 1,062 522 532

Regulation $7.12 -2% -21% Output Gap- Low Thresh. (MW/hr) 110 71 130

Spinning Reserves $2.22 73% 69% Other:

Supplemental Reserves $1.41 182% 180% SPP M2M Coordination

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.

• The summer 2015 quarter was generally characterized by moderate weather throughout the footprint and continued low fuel prices.

The South region, however, did experience record peak load conditions during July.

• Overall, the market performed competitively and reliably this summer.

• Considerably lower gas prices this summer compared to last year drove down average system-wide energy prices.

Real-time energy prices fell 17 percent from last year to $28.78 per MWh.

Similarly, day-ahead prices fell 19 percent to $29.26 per MWh.

• Congestion levels were typical for the summer and both day-ahead and real-time congestion was similar to last summer.

• Peaking units were more heavily used during this summer than in prior quarters and the prior summer, which coincides with increases in real-time RSG payments.

• Price convergence was generally good, but was not good at congested locations in in Texas and Louisiana.

• Market-to-Market coordination with SPP has reduced inefficient congestion impacts relative to TLR, but MISO and SPP are trying resolve a number of issues.

• This report also provides a preliminary evaluation of ELMP, which indicates that expanding the online pricing for peaking resources is likely warranted.

Summary of Summer 2015

- 3 -

Price Convergence (Slide 12)

• Price convergence was generally good in uncongested locations.

• However, the market continued to not quickly respond to congestion related price

differences in the day-ahead and real-time markets.

Various line and unit outages near the Louisiana Hub caused high values of congestion

that was underpriced in the day-ahead market in June and August. The patterns of congestion around the Louisiana Hub is similar to what was observed last quarter.

Commitments in Texas for VLR caused congestion on lines into the load pocket, which was not sufficiently priced in the day-ahead market during August.

MISO/SPP JOA Payments (Slide 19)

• Price impacts from SPP FGs have declined since M2M began in March.

• M2M startup issues resulted in some inefficiency and ongoing settlement disputes.

Some of these startup issues have been resolved and should not reoccur.

Some issues have arisen related to swings in dispatch flows over M2M constraints:

– This sometimes occurs because the non-monitoring RTO dominates the flows.

– In this case, the constraint should be transferred to the other RTO, but MISO and SPP are developing other approaches.

Highlights from Summer 2015

- 4 -

Peaking Unit Usage (Slide 22)

• High temperatures in the South, in July particularly, caused peaking units to be more extensively committed in the day-ahead and real-time markets than usual.

Day-ahead average hourly commitments exceeded 700 MW per hour,

approximately three times typical rates because of high loads and VLR needs.

Additional real-time commitments resulted in more than 1100 MW of peaking

units running each hour during the quarter, double the amount from last summer.

More peaking resources were committed on days when load was under-scheduled,

which was generally due to higher than expected temperatures.

ELMP (Slide 27)

• The overall price effects of ELMP have been very small at most locations.

• The online pricing effects would be larger and more effective if a wider array of online

peaking resources were utilized by ELMP. Only roughly 1 percent of the online

peaking resources are eligible to set prices under ELMP.

• The offline pricing effects related to operating reserve shortages have been consistent

with expectations. We will be investigating price effects related to transmission

violations.

Highlights for Summer 2015

- 5 -

• We responded to FERC questions related to prior referrals regarding resources

failing to update real-time offers and we continued to meet with FERC staff on a weekly and monthly basis to discuss market outcomes.

• We continued discussions regarding interface pricing with SPP and PJM staff and stakeholders, making presentations at both PJM and SPP Seams Meetings.

• We presented a summary of the 2014 SOM and Recommendations to FERC staff.

• We received a Civil Investigative Demand from the Department of Justice

We provided the data requested and have had several discussions with DOJ staff

to discuss relevant market issues.

• We provided annual training to MISO MPs on Module D monitoring procedures and

MP responsibilities to provide cost, operating data, and to review references.

• MISO is reviewing the potential impact of future pseudo-tied capacity. We continue to recommend MISO not support pseudo-ties and instead implement

reciprocal procedures to guarantee the firm delivery of external capacity.

• The new mitigation framework and thresholds for RSG Mitigation in BCA and NCAs was implemented on June 30 and has operated as intended.

Submittals to External Entities and Other Issues

- 6 -

Day-Ahead Average Monthly Hub Prices

Summer 2013–2015

- 7 -

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$0

$15

$30

$45

$60

$75

Jun Jul Aug Jun Jul Aug Jun Jul Aug

Summer 2013 Summer 2014 Summer 2015

Na

tura

l G

as

Pri

ce (

$/M

MB

tu)

$/M

Wh

Minnesota Hub Indiana Hub

Michigan Hub Louisiana Hub

Texas Hub Arkansas Hub

Mean Gas Price

All-In Price

2013 –2015

- 8 -

$0

$15

$30

$45

$60

$75

$0

$4

$8

$12

$16

$20

13 14 15 J F M A M J J A S O N D J F M A M J J A

Summer 2014 2015

All

in

Pri

ce (

$/W

Mh

)

(Na

tura

l G

as

Pri

ce (

$/M

MB

tu)

Energy

Energy (Shortage)

Uplift

Ancillary Services

Capacity

Natural Gas Price

Monthly Average Ancillary Service Prices

Regulation and Contingency Reserves, 2014–2015

- 9 -

-$3

$0

$3

$6

$9

$12

J J A S O N D J F MAM J J A J J A S O N D J F MAM J J A J J A S O N D J F MAM J J A

2014 2015 2014 2015 2014 2015

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

MISO Fuel Prices

2013–2015

- 10 -

0.00

0.50

1.00

1.50

2.00

2.50 $0.00

$5.00

$10.00

$15.00

$20.00

$25.00

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

2014 2015

Ind

ex (

Ja

n 2

01

3=

1)

$/M

MB

tu

$42

10.211.8

$37

3.0

2013 2014 2015

Oil $21.50 $20.77 $12.08

Natural Gas $3.69 $4.23 $2.80

Summer Average 2013 2014 2015

IB Coal $1.86 $1.91 $1.52

PRB Coal $0.61 $0.70 $0.58

Summer Average

Load and Weather Patterns

Summer 2013–2015

- 11 -

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

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

0

25,000

50,000

75,000

100,000

125,000

150,000

0

500

1,000

1,500

2,000

2,500

3,000

13 14 15 13 14 15 13 14 15 13 14 15

Summer Jun Jul Aug

Lo

ad

(M

W)

Ad

just

ed D

egre

e D

ay

s

Midwest South

Average Load

Peak Load

CDD

HDD

Historical Avg.

Membership

Day-Ahead and Real-Time Price Convergence

2014–2015

- 12 -

-$10

$0

$10

$20

$30

$40

$50

$60

$70

$80

DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT DA RT

14 15 J J A S O N D J F M A M J J A

Sum. Avg. 2014 2015

$/M

Wh

Average Price Difference

Absolute Difference

RT RSG Rate

Average RT Price

DA RSG Rate

Average DA Price

Indiana Hub 3 2 3 4 2 -2 3 0 2 1 1 0 1 2 3 1 2Michigan Hub 1 0 -5 4 3 -2 3 0 2 7 6 -1 2 0 0 0 0Minnesota Hub 3 1 4 1 3 0 3 4 -5 -1 0 -1 2 3 -1 3 0WUMS Area 1 2 0 2 2 -5 1 3 1 1 0 2 4 1 3 3 0Arkansas Hub 5 0 10 5 2 -4 -1 3 2 -3 3 -3 4 3 3 -3 0Louisiana Hub 2 -5 1 4 3 -4 2 2 4 0 2 -10 -2 0 -10 1 -5Texas Hub 13 -1 31 3 5 2 1 2 5 -1 1 -5 4 -10 4 0 -7

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

Day-Ahead Peak Hour Load Scheduling

2014–2015

- 13 -

80%

84%

88%

92%

96%

100%

104%

13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015

Sh

are

of

Act

ua

l L

oa

d

Net Virtual Supply

Net Virtual Load

Price Based Load

Fixed Load

Share of Actual Load (%)

All Hours

Peak Hours

Midwest

Peak Hours

South

98.9

100.0

98.1

100.1

100.2

99.8

98.7

99.0

99.7

99.0

99.1

98.7

97.9

98.3

98.3

97.4

98.4

98.6

98.3

99.6

97.4

99.5

99.8

99.5

98.8

100.2

100.7

101.1

99.9

99.7

99.2

98.9

99.1

97.3

97.2

97.9

102.0

99.7

102.7

102.5

100.7

99.5

99.7

99.4

97.0

97.9

97.7

97.3

100.2

99.0

98.7

99.9

100.5

Virtual Load and Supply

2014–2015

- 14 -

18,000

15,000

12,000

9,000

6,000

3,000

0

3,000

6,000

9,000

12,000

15,000

18,000

21,000

13 14 15 J J A S O N D J F M A M J J A 13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015 Summer 2014 2015

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

Spring 2014–2015

- 15 -

18,000

15,000

12,000

9,000

6,000

3,000

0

3,000

6,000

9,000

12,000

15,000

18,000

21,000

13 14 15 J J A S O N D J F M A M J J A 13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015 Summer 2014 2015

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

2014–2015

- 16 -

-$2

$0

$2

$4-$15 M

-$10 M

-$5 M

$0 M

$5 M

$10 M

$15 M

$20 M

$25 M

13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015

Pro

fits

per

MW

To

tal

Pro

fits

Supply

Demand

Gross

Percent Screened

Demand 1.6 2.3 1.6 3.2 1.7 2.0 1.3 1.9 1.8 1.2 1.6 3.0 1.7 1.0 1.7 1.6 1.6 1.7

Supply 0.7 0.8 0.3 1.6 0.7 0.2 0.8 1.4 1.0 1.0 0.6 1.0 1.0 0.9 1.0 0.4 0.4 0.2

Total 1.2 1.7 1.0 2.5 1.3 1.2 1.1 1.7 1.5 1.1 1.1 2.1 1.4 1.0 1.4 0.9 1.0 1.0

Day-Ahead Congestion, Balancing Congestion

and FTR Underfunding, 2014–2015

- 17 -

-$15M

$0M

$15M

$0 M

$50 M

$100 M

$150 M

$200 M

$250 M

$300 M

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

2014 2015

2014 2015

Balancing Congestion Revenue ($5.4 M) ($3.6 M)

DA Congestion Revenues $210.3 M $196.3 M

FTR Surplus (Shortfall) ($5.8 M) $9.1 M

FTR Funding (%) 98.3% 102.5%

Summer Totals

Value of Real-Time Congestion

2014–2015

- 18 -

$0

$100

$200

$300

$400

$500

13 14 15 J J A S O N D J F M A M J J A

Summer Avg. 2014 2015

Co

ng

esti

on

Va

lue

($ M

illi

on

s)

Sum 14 Spr 15 Sum 15

Midwest 231.1 M 271.5 M 189.7 M

Transfer Constraints 10.9 M 7.8 M 15.3 M

South 88.6 M 85.0 M 137.2 M

Total RT Value 330.6 M 364.3 M 342.2 M

DA Congestion Revenue 210.3 M 217.3 M 196.3 M

FTR Surplus/(Shortfall) (5.8 M) 11.7 M 9.1 M

Congestion Costs on SPP Flowgates

2014–2015

- 19 -

0%

10%

20%

30%

-$4

-$2

$0

$2

$4

$6

$8

$10

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

2014 2015

Sh

are

of

Eff

ect

on

LM

P

Co

ng

esti

on

Va

lue

($ M

illi

on

s)

JOA Payments

Balancing Congestion Cost

Day-Ahead Congestion Cost

Share of Effect on Generation LMP

Peaking Resource Dispatch

2014–2015

- 20 -

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015

In-M

erit

MW

(%

)

Av

era

ge

Ho

url

y M

W

Real-Time Local Voltage

Real-Time Congestion

Real-Time Capacity

Committed Day-Ahead

Percent In-Merit

ELMP Price Effects

Market-Wide

- 21 -

2.5%

2.0%

1.5%

1.0%

0.5%

0%

0.5%

1.0%

1.5%

2.0%

2.5%

-$0.5

-$0.4

-$0.3

-$0.2

-$0.1

$0

$0.1

$0.2

$0.3

$0.4

$0.5

Mar Apr May Jun Jul Aug

2015

% o

f In

terv

als

Aff

ecte

d

Av

era

ge

Pri

ce E

ffec

t ($

/MW

h)

Dec

rea

se

I

ncr

ease

Decreased Prices

Increased Prices

Intervals Affected

Aggregate Price Effects ($/MWh)

Spring 2015 0.0088

Summer 2015 -0.0782

SMP Increase 1.51 0.71 0.61 1.37 1.37 2.03

SMP Decrease -63.99 -8.04 -1.21 -6.19 -10.44 -33.45

ELMP Price Effects

Most Affected Locations

- 22 -

20%

16%

12%

8%

4%

0%

4%

8%

12%

16%

20%

-$2.0

-$1.6

-$1.2

-$0.8

-$0.4

$0

$0.4

$0.8

$1.2

$1.6

$2.0

Mar Apr May Jun Jul Aug

2015

% o

f In

terv

als

Aff

ecte

d

Av

era

ge

Pri

ce E

ffec

t ($

/MW

h)

LMP Greatest Positive Impact

LMP Greatest Negative Impact

% of Intervals Affected

Peaking Units Eligible to Set Prices

- 23 -

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$3,500,000

$4,000,000

$4,500,000

0

50

100

150

200

250

300

350

10 minutes 30 minutes 1 hour > 1 hour

RS

G C

ost

s ($

/MW

h)

Av

era

ge

Qu

an

tity

Dis

pa

tch

ed i

n Q

ua

rter

(M

W)

Peaking Resources by Start Time

In Merit

Not Covering

Commit Costs

Out of Merit

RSG Paid

Day-Ahead RSG Payments

Summer 2014–2015

- 24 -

$0

$10

$20

$30

$40

13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015

RS

G P

ay

men

ts (

$ M

illi

on

s)

Midwest South Total

Fuel-Adjusted RSG: VLR $4.5 M $17.7 M $22.2 M

Fuel-Adjusted RSG: Capacity $2.3 M $6.5 M $8.9 M

VLR RSG not Allocated $1.4 M $1.4 M

Other Capacity RSG $2.3 M $5.2 M $7.5 M

Total Nominal RSG $5.4 M $15.7 M $21.1 M

RSG Mitigation $0.8 M

RSG Distribution: Summer 2015

Real-Time RSG Payments

Summer 2014–2015

- 25 -

$0

$10

$20

$30

$40

13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015

RS

G P

ay

men

ts (

$ M

illi

on

s)

RSG Distribution: Summer 2015 Midwest South Total

Fuel-Adjusted RSG: VLR $0.6 M $3.4 M $4.0 M

Fuel-Adjusted RSG: Congestion $1.3 M $3.0 M $4.3 M

Fuel-Adjusted RSG: Capacity $18.1 M $4.4 M $22.5 M

Total Nominal RSG $13.3 M $6.9 M $20.2 M

RSG Mitigation $0.1 M $0.1 M $0.2 M

Price Volatility Make Whole Payments

2014–2015

- 26 -

$0

$3

$6

$9

$12

$0

$3

$6

$9

$12

13 14 15 J J A S O N D J F M A M J J A

Sum. Avg. 2014 2015

Vo

lati

lity

(Av

era

ge

Inte

rva

l P

rice

Ch

an

ge)

Up

lift

Pa

ym

ents

($

Mil

lio

ns)

DAMAP (Midwest) RTORSGP (Midwest)

DAMAP (South) RTORSGP (South)

SMP Volatility LMP Volatility

Wind Output in Real-Time and Day-Ahead Markets

7-Day Moving Average, 2014–2015

- 27 -

-1,500

0

1,500

3,000

4,500

6,000

7,500

9,000

10,500

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

2014 2015

Qu

an

tity

(M

W)

13 1 4 15

Summer Avg. 2014 2015

Day-Ahead Wind

Net Virtual Supply

Real-Time Wind

Wind Scheduling Difference

Net Scheduling Difference

Generation Outage Rates

2014–2015

- 28 -

0%

5%

10%

15%

20%

25%

30%

13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015

Sh

are

of

Ca

pa

city

Summer 2013 2014 2015

Short-Term Forced Outages 2.0% 1.8% 2.0%

Long-Term Forced Outages 2.1% 2.8% 2.7%

Planned Outages 3.0% 4.0% 3.5%

Total 7.2% 8.6% 8.2%

Monthly Output Gap

2014–2015

- 29 -

0.0%

0.1%

0.2%

0.3%

0.4%

0.5%

0

50

100

150

200

250

13 14 15 J J A S O N D J F M A M J J A

Summer 2014 2015

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

Online

Offline

Online

2 17 47 13 21 15 20 9 19 50 11 18 5 3 11 34 49 58

8 39 16 54 41 21 60 62 75 36 6 24 16 10 19 24 9 14

4 23 54 18 29 22 32 14 21 52 12 33 5 4 15 43 54 65

35 107 56 150 107 65 131 149 147 92 34 72 53 46 90 68 43 56

Day-Ahead And Real-Time Energy Mitigation

2014–2015

- 30 -

0

250

500

750

1000

1250

1500

0

100

200

300

400

500

600

131415 J J A S O N D J F M A M J J A 131415 J J A S O N D J F M A M J J A

Sum.

Tot.

2014 2015 Sum.

Tot.

2014 2015

BCA 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

2014–2015

- 31 -

0

30

60

90

120

150

180

210

$0 M

$1 M

$2 M

$3 M

$4 M

$5 M

$6 M

$7 M

13 14 15 J J A S O N D J F M A M J J A

Sum. Avg. 2014 2015

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

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

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

ORCA Operations Reliability Coordination

Agreement

ORDC Operating Reserve Demand Curve

List of Acronyms

- 32 -

PRA Planning Resource Auction

PVMWP Price Volatility Make Whole

Payment

RAC Resource Adequacy Construct

RSG Revenue Sufficiency Guarantee

RTORSGP Real-Time Offer Revenue

Sufficiency Guarantee Payment

SMP System Marginal Price

SOM State of the Market

SRPBC Sub-Regional Power Balance

Constraint

TLR Transmission Line Loading

Relief

TCDC Transmission Constraint

Demand Curve

VCA Voluntary Capacity Auction

VLR Voltage and Local Reliability

WPP Weekly Procurement Process

WUMS Wisconsin Upper Michigan

System