imm quarterly report: summer 2015 june august...september 23, 2015 imm quarterly report: summer 2015...
TRANSCRIPT
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