role of system operator opportunities for...
TRANSCRIPT
Role of System Operator
Opportunities for storage
2
National Grid
UK and US Electricity and Gas
Transmission & Distribution
3
National Grid – UK – electricity
Transmission Owner
(England and Wales)
System design
Project management
Engineering and maintenance
~7,200km of overhead line; ~675km of underground cable; and 337 substations at 244 sites.
System Operator
(Great Britain)
System Planning
System Operation
Market Facilitation
Energy Trading
•Anglo-French Interconnector (2GW) •BritNed Interconnector (1GW) •North & South Irish connection (1.1GW) + planned new links
2010/2011 GB Demands
15000
20000
25000
30000
35000
40000
45000
50000
55000
60000
30
130
230
330
430
530
630
730
830
930
1030
1130
1230
1330
1430
1530
1630
1730
1830
1930
2030
2130
2230
2330
Time
Na
tio
na
l G
rid
De
ma
nd
(M
W)
Summer Minimum
Typical Summer
Typical Winter
Winter Maximum
Typical summer and winter GB
demand profiles N
ati
on
al G
rid
Dem
an
d (
GW
)
60
55
50
45
40
35
30
25
20
15
GB Installed Capacity (2103/14)
5
1,467 0
20,454
31,887
1,122
4,0000
9,471
1,1232,744
3,6693,368
GB Installed Capacity (2013/14)
Biomass
CCS
Coal
Gas
Hydro
Interconnector
Marine
Nuclear
Oil
Pumped Storage
Onshore Wind
GB Installed Capacity (2013/14)
Biomass 1,467 1.8%
CCS 0 0.0%
Coal 20,454 25.8%
Gas 31,887 40.2%
Hydro 1,122 1.4%
Interconnector 4,000 5.0%
Marine 0 0.0%
Nuclear 9,471 11.9%
Oil 1,123 1.4%
Pumped Storage 2,744 3.5%
Onshore Wind 3,669 4.6%
Offshore Wind 3,368 4.2%
Total 79,305 100.0%
Key Market Principles
6
Market Balancing ceases at Gate Closure (rolling 1hr ahead of real time)
Market ceases balancing at Gate Closure (1hr ahead of real time). The System Operator then balances the system (second by second) and is the sole counterparty to any further trades
Imbalance Cashed Out post event
Market participants are incentivised to balance their metered input / output with their contracted position through cashing out their
imbalance at a less favourable price
Market Balancing – ‘ Self Dispatch’
Market (generation and supply) is the principle balancing process (by half hour)
Participants need to forecast demand and wind power
Economic, Efficient and Secure
The System Operator has a licence condition to operate a secure, economic and co-ordinated system; it has an incentive scheme to
reward efficient operation
Post Gate Balancing ( 1 hr ahead)
The System Operator then balances the system (second by second) and is the sole counterparty to any further trades
Actions are taken in advance via Commercial Services
Forecasting, Planning & Information
System Operator forecasts demand and wind power
Physical information received from market
Market – Primary Balancer System Operator – Residual
Balancer
Bilateral
trading
activities
Meter
readings
Gate
closure
Real time
1 hour
Bid / offer
acceptances
Balancing
mechanism
BM data
~1,500,000
items /day Bids/Offers
Op Data
FPNs
~1000
Balancing
actions/day
Settlement CONTRACT VOLUMES
BM
actions
National Grid Forecasting & ‘Dispatch’
The Balancing Mechanism and information
Market Forecasting & Self Dispatch
~98% of energy
balancing done by
market (by half hr)
~2% of energy
balancing by System
Operator (sec by sec)
+ 0.5 GW
+ 0.5 GW
+ 1 GW
+ 1.5 GW
+ 1 GW
- 2 GW
Temperature(1°C fall in cold conditions)
Cloud cover
(clear sky to thick cloud)
Precipitation
(no rain to heavy rain)
Temperature(1°C rise in hot conditions)
Cooling power
(10 mph rise in cold conditions)
Embedded Wind Power
(Maximum output)
Demand and Wind Forecasting
8
Ofgem FIT Regiser: Link
Latest Installed Solar: 1610 MW
Latest Installed Wind: 1995 MW
Embedded Generation Estimates Last run: 15-Apr-2013 12:09:12
14-APR-2013 15-APR-2013 16-APR-2013
05:00 08:00 12:00 17:00 21:00 00:00 05:00 08:00 12:00 17:00 21:00 00:00 05:00 08:00 12:00 17:00 21:00
Solar (MW) 0 157 1282 558 4 0 0 250 1288 919 0 0 0 274 1288 1059 1
Wind (MW) 1377 1501 1562 1489 1298 1277 1245 1241 1344 1168 943 1059 1322 1450 1632 1519 1004
Total (MW) 1377 1658 2844 2047 1302 1277 1245 1491 2632 2087 943 1059 1322 1724 2920 2578 1005
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
14
-AP
R-2
01
3
05
:00
08
:00
12
:00
17
:00
21
:00
15
-AP
R-2
01
3
05
:00
08
:00
12
:00
17
:00
21
:00
16
-AP
R-2
01
3
05
:00
08
:00
12
:00
17
:00
21
:00
Em
be
dd
ed
Ge
ne
rati
on
/ M
W
0
500
1,000
1,500
2,000
2,500
20
11
03
01
20
11
04
15
20
11
05
30
20
11
07
14
20
11
08
28
20
11
10
12
20
11
11
26
20
12
01
10
20
12
02
24
20
12
04
09
20
12
05
24
20
12
07
08
20
12
08
22
20
12
10
06
20
12
11
20
20
13
01
04
20
13
02
18
20
13
04
04
20
13
05
19
20
13
07
03
20
13
08
17
20
13
10
01
20
13
11
15
20
13
12
30
PV Installed Capacity PV Output @ 1200
Progressive
Demand
Control
Domestic Consumers
unlikely to notice if
Demand Control by voltage
reduction <5% total
OK Notice of Insufficient
System Margin NISM High Risk of
Demand
Reduction
HRDR
Demand
Control
Imminent
DCI
Short Term Operating Reserve (STOR)
Contingency
Reserve
Regulating Reserve
Low Frequency Response
Demand
Reserve requirements
10
10 s 60 s Time
49.5
49.2
Fre
qu
en
cy
(Hz)
50.0
49.8
50.2
30 s
Primary(10-30s)
Incident
(e.g. generation loss)
Secondary (30s - 30min)
Reserve
49.0
48.8
47.0
Lower Statutory Limit
50.5 Upper Statutory Limit
52.0
Managing Frequency
Demand Disconnection
Generation Tripping
Upper Operational Limit
Lower Operational Limit
Lowest ‘Planned’ Limit
30 mins
Ancillary Services
Mandatory Services
Mandatory Capability from ‘Transmission connected’
generators for:
Primary, Secondary and High frequency response (provider specified holding price)
Deload cost paid via
Balancing Mechanism
Reactive range (paid
for by a index based
price)
Commercial Services
More economic solutions to mandatory services and reserve
that comprise one or more of:
Firm contracts
(for a committed period of
time)
Enhanced capability / different technical
parameters
Services from
providers other than
main generators
11
Committed in operational timescales (no availability fee)
Committed before or in operational timescales
Commercial Services
12
Firm Frequency Response
(5s – 30 mins)
• Availability & Utilisation prices
• Monthly tendered service
• Window of service
• Mostly generation but open to all
• Automatic service
• Performance monitoring
Firm Reserve
STOR (20 mins) and Fast Reserve (2 mins)
• Availability & Utilisation Prices
• 3 times year / monthly tenders
• BM and bespoke dispatch system
• Performance monitoring / payment penalties
Reserve
BM Start Up / Energy Trades
• Short term call off
• Utilisation prices – pre agreed / negotiated short term
• Framework Agreements
Reactive
Enhanced reactive power
• Utilisation / avilability
• Ad hoc / tender
Firm Constraint Management
• Availability & utilisation
• Ad hoc tender
• Weeks ahead
Intertrips
• Availability / utilisation
• Bilateral / framework
STOR: BM: OCGTs, Pumped Storage NBM:
Diesel, OCGTs, Hydro, Biomass, CCGT.
Fast Reserve: Pumped storage, Sync Gas
Synchronous generators
Demand side in development
Coal and Oil, units in cold storage
Synchronous generators Synchronous generators, wind,
embedded./demand side in development
Commercial and operational:
interconnectors, wind, some large generator
sites
Ancillary Service Breakdown
Typical contracted levels (figures vary with economics of tenders received)
600-1000MW for Firm Frequency Response
300-400MW for Fast Reserve
2200-2500MW for STOR ~50% of these are Non-BM units
13
Balancing Services Costs
£271
-£14
£1
£70
£97
£56
£5£17
£1
£52
£69
£9
£100
£16
-£100
-£50
£0
£50
£100
£150
£200
£250
£300
Re
active
ST
OR
+ B
M
Utilis
atio
n
Ma
nd
ato
ry
Fre
qu
en
cy
Re
sp
on
se
Co
mm
erc
ial
Fre
qu
en
cy
Re
sp
on
se
Fa
st
Sta
rt
Bla
ck S
tart
BM
Sta
rt U
p
Fa
st
Re
se
rve
(Te
nd
ere
d)
Fa
st
Re
se
rve
(No
n-T
en
de
red
)
Co
nstr
ain
ts a
nd
Inte
rtri
ps
SO
-SO
BM
Co
nstr
ain
ts
Tra
de
s
PG
BT
s
Fe
es &
Lia
bili
tie
s
£m
2013/14
How the System Operator is funded
Balancing Services Use of System (BSUoS) paid by Generators &
Demand that use the Transmission System (~£1.50 / MWh) Includes:
Internal SO costs
‘External Costs’ : - Balancing Mechanism and Ancillary Services
(~£1bn / year)
SO incentive scheme to manage external costs (+/-£25m)
The Network is paid for separately via Transmission Charges
14
15
Future GB Wind Capacity Scenarios Until 2020
0
5,000
10,000
15,000
20,000
25,000
30,0002
00
0
20
01
20
02
20
03
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
Year
Ins
tall
ed
Win
d C
ap
ac
ity
/ M
W
Slow Progression Accelerated Growth
16
The changing grid
‘IFA’
France
2GW
existing electricity network
potential wind farm sites
potential nuclear
sites
interconnectors
France
2GW
‘Britned’
Netherlands
1.2GW
Belgium
1GW
Norway
1.4GW
‘East-West’
Ireland
500MW
‘Moyle’
Ireland
500MW*
Denmark
1GW
Arrows are illustrative and do not show connection points.
Cumulative contracted generation (GW)
0
10
20
30
40
50
60
70
80
90
100
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
*
Interconnector Renewable Non-renewable
Source: National Grid TNQCU – March 2013.
* No new contracted generation after 2025.
Renewable fuel types: Biomass, Hydro, Tidal, Wave, Wind
Further Information
High Level Service Guide
http://www2.nationalgrid.com/uk/services/balancing-
services/service-guides/
Monthly Balancing Services Summary
http://www2.nationalgrid.com/UK/Industry-
information/Electricity-transmission-operational-
data/Report-explorer/Services-Reports/
17
18 18
Generation Demand
Variable generation
0
200
400
600
800
1,000
1,200
1,400
1,600
0
200
400
600
800
1,000
1,200
1,400
1,600
01
-Ja
n
05
-Ja
n
10
-Ja
n
15
-Ja
n
20
-Ja
n
25
-Ja
n
30
-Ja
n
01
-Ja
n
05
-Ja
n
10
-Ja
n
15
-Ja
n
20
-Ja
n
25
-Ja
n
30
-Ja
n
MW
Large generation
Inflexible generation
Active distribution networks
Smart(er)
grids &
meters, energy
storage
Active demand
Time of use tariffs
30
35
40
45
50
55
60
00
:00
01
:00
02
:00
03
:00
04
:00
05
:00
06
:00
07
:00
08
:00
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:00
10
:00
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:00
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:00
20
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:00
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:00
23
:00
Time of Day
Ele
ctr
icit
y D
em
an
d (
GW
)
2020 Demand ~ 15GWh (daily) - 1.5million vehicles
Typical winter dailydemand
Pe
ak
Co
mm
uti
ng
Tim
e
12,000 miles p.a.
Pe
ak
Co
mm
uti
ng
Tim
e
Optimal Charging
Period
Distributed generation
Smarter transmission
Smart zones
HVDC
Series
compensation
WAM
Balancing supply and demand?
Energy Storage.
Capacitors
Flywheels
Batteries
Diesel Generators
Superconducting Magnets
Pumped Storage
0.001
0.01
0.1
1
10
100
1000
0.1 1 10 100 1000 0.01 0.001 0.0001
Power, MW
Stored Energy, MWh
Applications/Markets
Segmentation of the Electrical Energy Storage Market
Uninterruptible Power Supplies
Large Arbitrage
Reserve
Small Arbitrage
Power Quality
Traction Supplies
Electric Vehicles
Technologies
Dinorwig
Interconnectors vs pump storage
1. Costs
Storage:
DECC pathway model NOAK pump store = £2000k/MW capital
cost with ~75% cycle efficiency
Assume ~£200k/MW/yr for financing and non-load op costs
Interconnection:
Western hvdc link £1.1b for a 400km @ 2400MW hvdc link =
£1150/MW/km with 2.5% loss
Assume ~£115k/MW/1000km/yr for financing and op costs
20
Interconnection vs pump storage (continued)
2. Benefits – pump store
Daily charge per MW = (24-t1) * 75% = 6 MWh
Arbitrage profit = (£50 * 6 – £15 * 8) = £180/day = £66k/MW/yr
Peak security contribution = CONE = £50k/MW/yr
Annual revenue = £116k/MW (cf annual cost £200k/MW )
21
£50/MWh
£15/MWh
t1 = 16h
Eg. marginal
fossil burn
Eg. marginal
renewables
Daily price curve
Interconnection vs pump storage (continued)
2. Benefits – 1000km E-W intercon giving 1hr local time difference
Arbitrage revenue = (£50 * 0.975 – £15) * 2 = £67/day = £25k/MW/yr
Peak security contributions = CONE both ends = £100k/MW/yr
Annual revenue = £125k/MW (cf annual cost £115k/MW )
22
£50/MWh
£15/MWh
t = 1h
Eg. marginal
fossil burn
Eg. marginal
renewables
Daily price curve
Sensitivities
Storage profit
(per MW per yr)
Intercon profit
(per MW per yr)
Base case -£84k +£10k
Low price = £5/MWh +£29k +£7k
High price = £100/MWh +£110k +£71k
1 hr more low price / day +£8k £0
50% chance of simultaneous
scarcity
£0 -£50k
50% less arbitrage revenues in
pickup/dropoff
£0 -£11k
50% of link on OH lines £0 +£78k
23
Home battery on PV array
Cost $3000 for 7 kWh @ 90% cycle efficiency = £200/yr financing
1kW convertor = 3hrs * 90% = 2.7 kWhr. Full store = 7 kWhr
1kW arbitrage profit = £0.150*2.7 – £0*3 = £0.41/day = £150/yr
Full storage arbitrage profit = £0.150*7 - £0*3 = £1.05/day = £380/yr
124
15p/kWh
1.5p/kWh
Eg. marginal fossil
+ Dx & Cap LRMC
Eg. marginal
renewables
Daily price curve
PV annual load factor ~=10% i.e. average charge of 3 hrs / day
(1kW fills half store on average, 2kW would make more use of full storage)