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

09

:00

10

:00

11

:00

12

:00

13

:00

14

:00

15

:00

16

:00

17

:00

18

:00

19

:00

20

:00

21

:00

22

: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)