Opportunities for storage National Grid UK and US Electricity and - - PowerPoint PPT Presentation

Role of System Operator Opportunities for storage

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National Grid

UK and US Electricity and Gas Transmission & Distribution

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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 National Grid Demand (MW)

Summer Minimum Typical Summer Typical Winter Winter Maximum

Typical summer and winter GB demand profiles

National Grid Demand (GW) 60 55 50 45 40 35 30 25 20 15

GB Installed Capacity (2103/14)

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1,467 20,454 31,887 1,122 4,000 9,471 1,123 2,744 3,669 3,368

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%

Coal 20,454

25.8%

Gas 31,887

40.2%

Hydro 1,122

1.4%

Interconnecto 4,000

5.0%

Marine

0.0%

Nuclear 9,471

11.9%

Oil 1,123

1.4%

Pumped Stora 2,744

3.5%

Onshore Win 3,669

4.6%

Offshore Win 3,368

4.2%

Total 79,305

100.0%

Key Market Principles

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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

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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) 157 1282 558 4 250 1288 919 274 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 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 14-APR-2013 05:00 08:00 12:00 17:00 21:00 15-APR-2013 05:00 08:00 12:00 17:00 21:00 16-APR-2013 05:00 08:00 12:00 17:00 21:00 Embedded Generation / MW

500 1,000 1,500 2,000 2,500 20110301 20110415 20110530 20110714 20110828 20111012 20111126 20120110 20120224 20120409 20120524 20120708 20120822 20121006 20121120 20130104 20130218 20130404 20130519 20130703 20130817 20131001 20131115 20131230 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

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10 s 60 s Time 49.5 49.2 Frequency (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

• ther than

main generators

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Committed in operational timescales (no availability fee) Committed before or in

• perational 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

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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

Reactive STOR + BM Utilisation Mandatory Frequency Response Commercial Frequency Response Fast Start Black Start BM Start Up Fast Reserve (Tendered) Fast Reserve (Non-Tendered) Constraints and Intertrips SO-SO BM Constraints Trades PGBTs Fees & Liabilities

£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

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Future GB Wind Capacity Scenarios Until 2020

5,000 10,000 15,000 20,000 25,000 30,000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year Installed Wind Capacity / MW

Slow Progression Accelerated Growth

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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) 10 20 30 40 50 60 70 80 90 100 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025* 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/

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Generation Demand

Variable generation

Large generation Inflexible generation Active distribution networks

Smart(er) grids & meters, energy storage

Active demand

Time of use tariffs

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

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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 )

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£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 )

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£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

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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

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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)