Highlights from the Quarterly Report on the
New York ISO Electricity Markets
Third Quarter of 2016
Pallas LeeVanSchaick
Potomac Economics
Market Monitoring Unit
Market Issues Working Group
November 29, 2016
Highlights and Market Summary:
Energy Market Outcomes and Congestion
•
This report summarizes market outcomes in the third quarter of 2016.
•
The energy markets performed competitively and variations in wholesale prices
were driven primarily by changes in fuel prices, demand, and supply availability.
•
Average all-in prices ranged from roughly $35/MWh in the North Zone to
$70/MWh in Long Island. (see slide 9)
 LBMPs rose moderately from 2015-Q3 in most areas partly because:
–
Average load levels rose ~600 MW and annual peak load rose by 1 GW primarily
because of warmer weather conditions. (see slide 11)
–
Hydro and nuclear output fell ~400 MW. (see slide 15)
–
North Zone was the only region where prices fell because of more frequent
congestion in September due to transmission outages. (see slide 20)
–
However, natural gas prices remained very low and actually fell 14 percent in
New York City, which helped offset the effect of higher load levels. (see slide 12)
 The largest LBMP change (+35%) was in Long Island because the Y49 line
outage greatly reduced imports from upstate for most of the quarter (see slide 20).
 Capacity costs fell 22 and 23 percent in NYC and Long Island from the previous
year. (see slide 9)
-2-
All-In Energy Price by Region
$100
NYISO Operations
Uplift
Natural Gas Price
Ancillary Services
$10
$9
$80
Energy
$8
$70
Capacity
$7
$60
$6
$50
$5
$40
$4
$30
$3
$20
$2
$10
$1
$0
$0
-$10
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Average Cost ($/MWh)
$90
$11
'14 2015 2016 '14 2015 2016 '14 2015 2016 '14 2015 2016 '14 2015 2016 '14 2015 2016 '14 2015 2016
West
Central NY
North
Capital Zone
LHV
NYC
Long Island
(Zone A)
(Zones BCE)
(Zone D)
(Zone F)
(Zones G-I)
(Zone J)
(Zone K)
Note: Natural Gas Price is based on the following gas indices (plus a transportation charge of $0.20/MMbtu): the Dominion
North index for West Zone and Central NY, the Iroquois Waddington index for North Zone, the Iroquois Zone 2 index for
Capital Zone and LI, the average of Texas Eastern M3 and Iroquois Zone 2 for LHV, the Transco Zone 6 (NY) index for
-- 39 -NYC. A 6.9 percent tax rate is also included NYC.
Natural Gas Price ($/MMBtu)
$110
Coal, Natural Gas, and Fuel Oil Prices
2015Q3 2016Q2 2016Q3
Ultra Low-Sulphur Kerosene
$14.20 $12.63 $12.87
Ultra Low-Sulphur Diesel Oil
$11.34 $9.91 $10.02
Fuel Oil #6 (Low-Sulphur Residual Oil) $7.12
$6.32
$7.22
Natural Gas (Tennessee Z6)
$2.34
$2.39
$2.74
Natural Gas (Iroquois Z2)
$2.84
$2.26
$2.84
Natural Gas (Transco Z6 (NY) )
$2.15
$1.65
$1.84
Natural Gas (Tx Eastern M3)
$1.33
$1.55
$1.33
Natural Gas (Dominion North)
$1.22
$1.47
$1.25
Central Appalachian Coal
$1.74
$1.40
$1.81
$18
Fuel and Coal Price ($/MMBtu)
$16
$14
$12
$10
$8
$6
$4
$2
$0
July
August
4 ---12
September
Real-Time Generation Output by Fuel Type
Quarter
Sub-Regioin Generation (GW)
6
5
4
3
21
Average Internal Generation by Fuel Type in NYCA (GW)
Nuclear
Hydro
Coal
5.02
4.03
5.11
2.63
3.08
2.94
0.34
0.10
0.25
2016 Q3
2016 Q2
2015 Q3
NG-CC NG-Other
6.19
4.96
6.07
3.21
1.87
2.84
Oil
Wind
Other
Total
0.10
0.02
0.06
0.28
0.36
0.26
0.31
0.30
0.32
18.08
14.72
17.84
18
15
Other
Wind
Oil
Coal
NG - Other
NG - CC
Hydro
Nuclear
12
9
2
6
1
3
0
JAS JAS
2015 2016
West
(Zone A)
JAS JAS
2015 2016
North
(Zone D)
JAS JAS
2015 2016
Central NY
(Zone BCE)
JAS JAS
2015 2016
Capital
(Zone F)
JAS JAS
2015 2016
LHV
(Zone GHI)
JAS JAS
2015 2016
NYC
(Zone J)
JAS JAS
2015 2016
Long Island
(Zone K)
JAS JAS
2015 2016
NYCA
Notes: Pumped-storage resources in pumping mode are treated as negative generation. “Other” includes
Methane, Refuse, Solar & Wood.
5 ---15
0
NYCA Generation(GW)
7
Net Imports Scheduled Across External Interfaces
Peak Hours (1-9pm)
Average Daily Real Time Scheduled Net Imports from External Interfaces
Peak Hours (13:00 - 21:00)
7000
Avg. Real-Time Scheduled Imports (MW)
Neptune CSC 1385 VFT OH HQ PJM NE HTP
2016 Q3
633
299
80
69
460 1569 454 -720
0
2016 Q2
578
240
76
24
753 1352 146 -547 17
2015 Q3
594
322 104
51
607 1468 257 -561 44
Quarter
6000
Scheduled Interchange (MW)
5000
Total
2843
2637
2886
4000
3000
2000
1000
0
-1000
-2000
Neptune
CSC
1385
VFT
Ontario
Hydro Quebec
PJM
NE Upstate
-3000
July
August
6 ---43
September
HTP
Real-Time Electricity Prices by Zone
$300
Quarter
Load Weighted Avg. Prices ($/MWh)
$270
$240
Load-Weighted Average Prices ($/MWh)
West
2016 Q3 $36.16
2016 Q2 $27.80
2015 Q3 $33.58
North
Capital Hud VL
$24.72
$11.81
$24.84
$31.41
$24.62
$31.24
$35.79
$25.39
$33.93
NYC
LI
$38.01
$27.00
$35.50
$56.53
$29.97
$42.00
$210
Long Island
New York City
Hudson Valley
Capital
West
North
$180
$150
$120
-$56
$90
$60
$30
$0
July
August
7 ---20
September
Highlights and Market Summary:
Demand Response Deployments – Scarcity Pricing
•
The evaluation suggests that:
 In retrospect, DR was needed to prevent a capacity deficiency (i.e., red line >
height of all areas) in a total of 18 intervals during the 5-hour deployment period.
 30-minute reserves were priced at $500/MWh during all 18 intervals.
– The improved consistency between price signals and actual system needs is a
significant enhancement under the new Scarcity Pricing Rule.
•
Nonetheless, in retrospect, the actual amount of demand response that was needed
to avoid a reserve shortage was just ~350 MW (indicated by the largest difference
between the red line and the height of all areas).
 This implies an over-deployment of DR (by more than 600 MW), which includes
~150 MW that was activated by utilities from their own DR programs.
 A total of $1.1 million of guarantee payments were made to DR resources for their
deployments (see slides 87-88).
8 ---24
Available Capacity and Real-Time Prices
During DR Activations
$500
Central
Zone
LBMP
$250
$0
LBMP ($/MWh)
NYCA, August 12
4,500
4,000
Capacity (MW)
3,500
3,000
2,500
2,000
1,500
30-Min Reserves - Scheduled
30-Min Reserves - Not Scheduled
Additional Avail Capacity - Non SRE
Additional Avail Capacity - SRE
2,620 MW + DR
30-Min Req = 2,620MW + DR - Additional Avail Cap
1,000
12
13
14
15
8/12/2016
9 ---25
16
17
18
Highlights and Market Summary:
Energy Market Outcomes and Congestion
•
DAM congestion revenues totaled $131 million, up 42 percent from the third
quarter of 2015. (see slide 55)
 Over 60 percent of the increase occurred on Long Island primarily because:
–
The Y49 line outage reduced imports from upstate during most of the quarter; and
–
The 677 line derating led to congestion from Northport to other areas of Long
Island throughout the quarter.
 West Zone accounted for most of the remaining increase as the congestion pattern
changed because of factors discussed in the next slide.
 Although congestion into Southeast New York was generally reduced following
the installation of the new “TOTS” projects, the benefits were largely offset by
the derating of the Branchburg-Ramapo line.
•
The Graduated Transmission Demand Curve (“GTDC”) project has led to higher
congestion prices. (see slides 71-75)
 Although most shortages (~70%) are still resolved using the constraint relaxation
method (rather than the GTDC), the GTDC project changed key parameters used
for constraint relaxation that has increased congestion shadow prices.
 Constraint relaxation can lead shadow prices to be unpredictably higher or lower
than the GTDC (regardless of severity of shortages).
-3-
DA and RT Congestion Value and Frequency
100%
50%
0%
Congestion Value ($ M)
Day-Ahead Real-Time
2015Q3
$92
$128
2016Q2
$94
$127
2016Q3
$131
$169
$60
Day-Ahead Congestion Value
Real-Time Congestion Value
Day-Ahead Congestion Frequency
Real-Time Congestion Frequency
$40
Q3
Q2
Q3
Q3
Q2
Q3
Q3
Q2
Q3
Q3
Q2
Q3
Q3
Q2
Q3
Q3
Q2
Q3
Q3
Q2
Q3
Q3
Q2
Q3
Q3
$0
Q2
$20
Q3
Congestion Value ($ in Millions)
$80
'15 2016 '15 2016 '15 2016 '15 2016 '15 2016 '15 2016 '15 2016 '15 2016 '15 2016
West Zone West to
North Central to Capital to NYC Lines Long
External All Other
Lines
Central
Zone
East
Hud VL
Island Interfaces
11 --- 55
Congestion Freq.
(% of Hrs)
by Transmission Path
Congestion Management with the GTDC
Transmission Shortage Pricing
West Zone Lines
Long Island Lines
Constraint Shadow Price ($/MWh)
$4,000
$3,500
2015 Q3
2016 Q3
GTDC
$3,000
$2,500
2015 Q3
2016 Q3
GTDC
$2,000
$1,500
$1,000
$500
$0
New York City Lines
All Other Constraints
Constraint Shadow Price ($/MWh)
$4,000
$3,500
2015 Q3
2016 Q3
GTDC
$3,000
$2,500
2015 Q3
2016 Q3
GTDC
$2,000
$1,500
$1,000
$500
$0
0
10
20
30
40
50
Transmission Shortage MW - 12
- 74- -
60 0
10
20
30
40
50
Transmission Shortage MW
60
Congestion Management with the GTDC
Limit Adjustments & Shortage Pricing, West Zone Constraints
$4,000
Constraint Shadow Price ($/MWh)
$3,500
2015 Q3
$3,000
$2,500
2016 Q3
GTDC
$2,000
$1,500
$1,000
$500
$0
-120
-100
-80
-60
-40
-20
0
20
Modeled Flow relative to Seasonal Constraint Limit minus CRM
- 75 -
40
60
Highlights and Market Summary:
Energy Market Outcomes and Congestion
•
West Zone congestion has been affected by significant market changes, including:
 (a) the implementation of GTDC in February 2016; (b) the retirements of coal
units in December 2015 and in March 2016; (c) the implementation of a
composite shift factor at Niagara plant in May 2016; (d) transmission upgrades in
May 2016; and (e) the S. Ripley-Dunkirk 230 kV line and Warren-Falconer 115
kV line being taken OOS during most of 2016-Q2.
 Also, volatile loop flows continued to exacerbate congestion. (see slides 61-63)
•
These challenges increase the need for efficient congestion management in the
West Zone.
 On 6/28, NYISO implemented enhanced loop flow assumptions in RTC and RTD
to deal with uncertainty about loop flows.
 However, we continue to observe: (see slides 64-70)
–
–
–
–
Under-utilization of 115kV circuits that are parallel to congested facilities,
Inefficiently-high generation from units that exacerbate 230kV congestion,
Under-commitment of West Zone units that relieve 115kV & 230kV congestion,
Shadow prices are not well correlated with the severity of congestion during
transmission shortages, which undermines scheduling incentives for importers
and other non-dispatchable resources.
-4-
Numbers Indicate % of All 5-Minute Intervals
For Each Congestion Value Category
1.6%
Avg Clockwise Loopflow (MW)
0.9%
260
240
220
200
180
160
140
120
100
80
60
40
20
0
-20
0.5%
0.2%
0.1%
0.2%
Lake Erie Loop Flow (LEC) MW
Share of Total Congestion Value
5-Minute Change in LEC MW
< $10K
UnCongested
Intervals
$10K 50K
$50K $100K $200K 100K
200K
300K
Congestion Value
During Congested Intervals
- 63 -
> $300K
40%
35%
30%
25%
20%
15%
10%
5%
0%
% of Total Cong. Value
West Zone Congestion and Clockwise Loop Flows
During the Third Quarter of 2016
200
Import/Export
Niagara Composite
Niagara Individual
Other Generator
Wind Generator
PAR Adjust
150
100
50
Forward Flow
0
-50
Relief Flow
-100
Niagara - Packard
Packard - Sawyer
Transmission Constraint and Shift Factor
- 66 -
10% to 15%
-10% to -5%
-15% to -10%
-20% to -15%
-25% to -20%
-30% to -25%
-35% to -30%
33%
10% to 15%
50%
5% to 10%
Packard - Sawyer
0% to 5%
80%
-5% to 0%
62%
-10% to -5%
-15% to -10%
-20% to -15%
-25% to -20%
-300
-30% to -25%
-250
Niagara - Packard
5% to 10%
-200
% of Total Redispatch MW Unavailable Niagara Redispatch
From Individual Niagara Units
Due To Composite SF
0% to 5%
Constraint
-5% to 0%
-150
-35% to -30%
Potential Flow Impact On the Constraint (MW)
West Zone Congestion and Niagara Generation Modeling
Potential Redispatch Options
West Zone Congestion and Niagara Generation Modeling
LBMPs by Generator & Under-Utilization of 115kV Circuits
Average LBMP ($/MWh)
$160
$140
West Zone
$120
Niagara 115 W
Niagara 115 E
$100
Niagara 230
$80
Congested Non-Congested
Intervals
Intervals
West Zone
Niag 115 W
$258.64
$89.30
$24.53
$23.73
Niag 115 E
Niag 230
$123.11
-$48.68
$23.67
$24.06
$60
$40
$20
$0
2,500
Quarter
Production
Cost Savings
($ Million)
Additional Niagara
Generation Potential
(GWh)
2016 Q3
$1.3
11.7
Additional Niagara
Generation
Potential
2,000
1,500
1,000
500
0
July
August
- 68 -
September
Generation (MWh)
Average LBMP ($/MWh)
Location
West Zone Congestion and Niagara Generation Modeling
Modeled Impact vs. Actual Impact
20
Actual Constraint Flow (Delta MW)
15
2016Q3
2015Q3
10
5
0
-5
-10
-15
-20
-20
-15
-10
-5
0
5
10
Modeled Constraint Flow (Delta MW)
15
20 -20
-15
-10
-5
0
5
10
Modeled Constraint Flow (Delta MW)
Average Constraint Flow Impact (Delta MW)
Absolute Value of:
2016-Q3 2015-Q3
Modeled Impact
3.6
9.6
Actual Impact
5.0
6.0
Modeled v Actual
2.4
4.9
- 70 -
15
20
Highlights and Market Summary:
Uplift and Revenue Shortfalls
•
Guarantee payments were $19M, down 7% from 2015-Q3. (see slides 78-88)
 Supplemental commitments and OOM dispatches fell in Western NY because of
transmission upgrades and in NYC because of generation being more economic
(relative to the rest of Eastern NY due to gas market conditions).
 However, these were offset by increased supplemental commitments and OOM
dispatches in Long Island because of higher load levels and transmission outages.
•
DAM congestion shortfalls were $20M, up $13M from 2015-Q3. (see slide 56)
 Transmission outages were the main driver – over $11M of shortfalls were
assigned to the responsible transmission owners.
 The remaining shortfalls accrued primarily on the West Zone constraints,
resulting largely from assumptions related to loop flows.
•
Balancing congestion shortfalls were $9M, up $3M from 2015-Q3. (see slide 57)
 TSA events on several days accounted for the majority of shortfalls.
–
TSA-related congestion shortfalls were notably higher than in the prior two
summers partly because of: a) higher load levels during TSA events; and b) less
congestion relief from the Ramapo line because of its derating.
 West Zone 230 kV facilities accounted for most of remaining shortfalls.
-6-
Frequency of Out-of-Merit Dispatch
by Region by Month
1200
Region
1000
Station - Hours
Station Name
New York City
1
2
Arthur Kill
Gowanus GT
Long Island
1
2
East Hampton GT
South Hampton GT
East Upstate
1
2
Bethleham
Gilboa
West Upstate
1
2
Milliken
Niagara
800
600
Station
Rank
All Other Stations
Station #2 (Second Most)
Station #1 (Most OOM Hours)
400
200
0
'15 Q3 '16 Q2 '16 Q3
New York City
'15 Q3 '16 Q2 '16 Q3
Long Island
'15 Q3 '16 Q2 '16 Q3
East Upstate
'15 Q3 '16 Q2 '16 Q3
West Upstate
Note: "Station #1" is the station with the highest number of out-of-merit ("OOM") hours in that region in the current quarter;
"Station #2" is that station with the second-highest number of OOM hours in that region in the current quarter.
Note: The NYISO also instructed Niagara to shift output among the generators at the station in order to secure certain 115kV and/or
230kV transmission facilities in, 790 hours in 2015-Q3, and 600 hours in 2016-Q2, and 430 hours in 2016-Q3. However,
these were not classified as Out-of-Merit in hours when the NYISO did not adjust the UOL or LOL of the Resource.
-- 20
84 --
Uplift Costs from Guarantee Payments
Local and Non-Local by Category
$2.0
$1.8
$1.6
Quarterly BPCG By Category (Million $)
Local
Statewide
Quarter
Day Real
Min Oil
Day Real
DAMAP
DAMAP
Ahead Time
Burn
Ahead Time
2016 Q3 $3.7 $5.0
$0.6
$1.1
$0.7 $2.5
$4.4
2016 Q2 $6.1 $2.4
$0.4
$0.0
$0.4 $1.0
$0.6
2015 Q3 $9.2 $5.0
$0.2
$0.6
$1.5 $1.9
$1.9
Total
EDRP/
SCR
$1.1
$0.0
$0.0
$19.0
$10.8
$20.4
$ Millions
$1.4
$1.2
$1.0
EDRP/SCR
Min Oil Burn
RT Statewide
RT Local
DAMAP Statewide
DAMAP Local
DAM Statewide
DAM Local
$0.8
$0.6
$0.4
$0.2
$0.0
July
August
September
Note: These data are based on information available at the reporting time and do not include some manual
adjustments to mitigation, so they can be different from final settlements.
-- 21
87 --
Day-Ahead Congestion Revenue Shortfalls
by Transmission Facility
$1.0
Day-ahead Congestion Residual ($ in Millions)
$0.8
$0.6
$0.4
$0.2
$0.0
-$0.2
Total
Shortfall ($M)
Category
West Zone Lines
Niagara Modeling Assumption
Loop Flow, Outage, & Other Assumptions
North Zone Lines
Long Island Lines
Excess Grandfathered TCCs
Outages & Other Assumptions
All Other Facilities
-$0.4
-$0.6
-$0.8
-$1.0
July
- -5622- -
August
-$1.2
$7.6
$1.9
$3.5
$8.6
-$0.1
September
Balancing Congestion Shortfalls
by Transmission Facility
Balancing Congestion Residual ($ in Millions)
$3.0
Total
Shortfall ($M)
Category
West Zone Lines
Niagara Modeling Assumption
Ramapo, ABC & JK PARs
Loop Flows, Outages and Other Factors
TSA Constraints
Ramapo, ABC & JK PARs
Deratings and Other Factors
External Interfaces
All Other Facilities
$2.5
$2.0
$1.5
$1.0
$0.5
$0.0
-$0.5
-$1.0
-$1.5
July
August
September
Note: The BMCR estimated above may differ from actual BMCR because the figure is partly based on real-time schedules
rather than metered values.
- 23 -
- 57 -
$1.4
$0.6
$2.0
$1.3
$8.1
-$1.4
-$1.2
Highlights and Market Summary:
Capacity Market
•
UCAP prices fell 20 percent in New York City and 23 percent in Long Island from
2015-Q3, but rose 11 percent in the G-J Locality. (see slides 98-99)
•
Average spot prices fell in NYC and Long Island primarily because of lower ICAP
requirements (5% in NYC and 2% in Long Island). These fell because of:
 Lower LCRs, which resulted partly from the TOTS projects that increased import
capability into SENY; and
 Lower peak load forecast.
•
G-J Locality spot prices rose because the decrease in capacity supply was larger
than the decrease in the ICAP requirement.
•
In ROS, average spot prices were relatively unchanged from the previous year
because of the combined effect of following factors:
 Slightly lower ICAP requirement, which reflected the net effect of lower peak
load forecast and a higher IRM.
 A decrease in internal ICAP supply because of retirements, mothballing, and
outages.
 Higher sales from external resources (partly offset by lower SCR sales).
-5-
Key Drivers of Capacity Market Results
NYCA
NYC
LI
G-J Locality
Avg. Spot Price
2016 Q3 ($/kW-Month)
3.74
12.21
4.42
% Change from 2015 Q3
2%
-20%
-23%
Change in Demand
Load Forecast (MW)
-209
-136
-61
IRM/LCR
0.5%
-3.0%
-1.0%
2016 Summer
117.5% 80.5% 102.5%
2015 Summer
117.0% 83.5% 103.5%
ICAP Requirement (MW)
-77
-467
-117
Change in ICAP Supply (MW)
Reductions Due to: Retirement (R), ICAP Inegilible FO (FO), Mothball (M)
R - Huntley 67 & 68 (Mar-16)
-375
FO - Astoria GT 05,07,12,13 (Jan-16)
-58
-58
M - Astoria GT 08,10,11 (Jul-16)
-47
-47
R - Dunkirk 2 (Jan-16)
-75
M - Ravenswood 04,05,06 (May-16)
-49
-49
Changes Due to: DMNC Test
63
89
19
Changes in External & SCR Sales
537
-22
-18
Net Changes (MW)
-5
-87
0
- -2599- -
9.21
11%
-31
-0.5%
90.0%
90.5%
-109
-58
-47
-49
56
-23
-121