the impact of tidal lagoons on the gb power market · the impact of tidal lagoons on the gb power...

© 2016 Aurora Energy Research Limited. All rights reserved.

CONFIDENTIAL: NOT FOR EXTERNAL DISTRIBUTION

The impact of tidal lagoons on the GB power market

Aurora Energy Research

22 September 2016

2CONFIDENTIAL: NOT FOR EXTERNAL DISTRIBUTION

AE

R T

em

pla

te 2

016a

2

Executive summary

Source: Aurora Energy Research

1 Assuming average household consumes 4MWh of power a year

Aurora’s analysis finds that if 25GW of tidal were to enter the system by 2030,

- Tidal would provide more than 10% of GB’s total power generation, enough to power 9 million households1 in the

UK

- CO2 emission could be reduced by 36% in 2035, amounting to a total CO2 savings of 130MT in the GB power

system from 2020-2040

- This would cost the system an additional £0.7billion/year, translating to a £8-9 increase in annual household

electricity bills

If Hinkley C and subsequent nuclear projects were cancelled,

- Replacing nuclear with tidal would be cheaper than replacing nuclear with wind in terms of average cost of CO2

reduction, by around £11/tonne

- Replacing nuclear with tidal would also cost the system an additional £1.7billion, compared to replacing Hinkley

with CCGT

- However, tidal would provide the system with 19MT of CO2 savings per year, allowing UK to meet its carbon

target

Our analysis also finds that tidal imposes less indirect costs on the system, compared to wind;

- 25GW of tidal could save the system up to £270million in balancing market spending, compared to adding 15GW

of wind on the system

- Average intermittency costs from 2025-2040 is also lower for tidal at £14/MWh, compared to that of wind at

£17.5/MWh

Most of tidal’s intermittency cost is driven by the need for back-up capacity. Given the predictable nature of the back-

up required, these costs could potentially be reduced through direct contracting with dispatchable capacity or other

bespoke mechanisms.


AE

R T

em

pla

te 2

016a

1. System impact: direct costs to consumers

– Scenarios with Hinkley C

– Scenarios with no Hinkley C

2. Other impact: indirect costs

3. Appendix

Contents


AE

R T

em

pla

te 2

016a

4

We ran four scenarios to examine the potential impact of tidal lagoons on the GB energy market


Scenario Description

Base caseAurora’s base case forecast (with Hinkley C)

No tidal to enter

Swansea only 0.3GW of tidal to enter in 2020

Swansea & Cardiff 3.6GW of tidal by 2027

All lagoons 25.3GW of tidal by 2030

SYSTEM IMPACT: WITH HINKLEY


AE

R T

em

pla

te 2

016a

5

The entry of tidal results in less CCGT and peaking plants entering the market, but more batteries


1 Peaking includes both OCGT and reciprocating engines

2 Others include all renewables (biomass, solar, onshore & offshore wind, hydro and marine), nuclear and interconnector

Tidal provides reliable and predictable generation which competes with CCGT for baseload generation, driving down CCGT entry

More batteries also enter to take advantage of tidal’sintraday production pattern

This results in less peakers entering as batteries provide cheap flexible capacity

83.8 83.8 83.8

15.0 15.4

17.4 17.9 16.314.3

11.214.3

25.3

4.1

Swansea

only

3.65.9

4.0

83.8

2.7

Swanse

a &

Cardiff

2.7

All

lagoons

2.72.7

0.3

Base

case

0.04.0

Installed capacity in 2035,

GW

OthersPeakingBattery Storage

Pumped StorageTidal CCGT



AE

R T

em

pla

te 2

016a

6

Tidal also provides significant amount of baseload generation, reducing the need for CCGT



2 Others include all renewables (biomass, solar, onshore & offshore wind, hydro and marine), nuclear and interconnector

By 2035, 25GW of tidal provides more than 10% of total power generation

Power generation from CCGT reduces by 35% from the base case as less CCGT enters and existing CCGTs run fewer hours

266 266 265 265

77 78 7149

36

-2

351

12

351

Swanse

a &

Cardiff

All

lagoons

10

-1-1 -2

1

-3-2

352

7

351

6

Swansea

only

Base

case

11

-1 -2

0

Others

Tidal

Pumped Storage

PeakingBattery Storage

CCGT

Power generation in 2035,

TWh



AE

R T

em

pla

te 2

016a

7

Tidal reduces wholesale prices in the 2030s


With all lagoons in place by 2030, baseload electricity price is reduced significantly. This is because tidal

– pushes more expensive plant out of merit

– sets the price in some periods; tidal sets the price 4% of the time in 2030

25

30

35

40

45

50

55

2015 2020 2025 2030 2035 2040

-£6/MWh

All lagoons

Swansea & Cardiff

Swansea only

Base caseBaseload electricity price

(2014 £/MWh)



AE

R T

em

pla

te 2

016a

8

The capacity market could cost £150m/year less on average, with CM prices £3/kW lower


Tidal provides significant amount of baseload generation

This reduces the need to procure additional CCGTs through the capacity market, resulting in lower CM prices

The lower CM prices save the system £150m/year on average from 2020 -2035

Capacity market prices,

£/kW

4

8

0

16

12

-£3/kW on average

2025/26 2030/312020/21 2035/36

All lagoons

Swansea & Cardiff

Swansea only

Base case



AE

R T

em

pla

te 2

016a

9

Household electricity bills increase by £8-9/year due to higher CfD costs


1. Calculated based on the following assumptions: domestic consumes 30% of total UK power generation and total number of households in UK projected to be 27million in 2030

System spending, 2020-2040 average

£ bn/year (real 2014)

4.4

18.1

0.34.0

4.4

0.34.0

Base case

18.1 17.0

All lagoons

+3%

26.9 27.627.126.9

Swansea

& Cardiff

4.0

18.0

0.2

4.7

4.00.4

Swansea only

6.3

CfDCapacity Market

Wholesale spendingROCs

Additional cost to annual

household electricity bill1

£0.25 £8.50£2.80

In the all lagoons scenario,

there is a £1.1bn savings in

wholesale market due to

lower electricity prices

The 25GW of tidal requires

an additional £1.9bn in CfD

spending



AE

R T

em

pla

te 2

016a

10

Tidal reduces power system CO2 emission by 11MT per year


1. Our emissions data are calculated on a per plant basis using an econometric model of historical plant dispatch, emissions and fuel use.

2. Average cost calculated based on average of 2027-2040 CO2 emissions and system spending

CO2 emissions1 per year,

MtCO2

0

40

60

2035

80

20

2030 204020202015 2025

-11

All lagoonsSwansea only

Swansea & CardiffBase case

Total CO2

emissions, 2020-

2040, MtCO2:

781

778

652

755


Average cost of

CO2 reduction2 =

£100/tonne


AE

R T

em

pla

te 2

016a


– Scenarios with Hinkley C

– Scenarios with no Hinkley C


3. Appendix

Contents


AE

R T

em

pla

te 2

016a

12

We also ran three scenarios where Hinkley does not get built


Scenario1 Description

CCGT to replace HinkleyMost economically efficient alternatives

However, carbon target is not met

Wind to replace Hinkley

Additional 15GW of wind on top of current level enters to replace nuclear

capacity

Carbon target is met

Tidal to replace Hinkley25GW of Tidal enters to replace nuclear capacity

Carbon target is met

1. We assume that if Hinkley C does not get built, all proposed nuclear projects in the UK are subsequently delayed indefinitely (Sizewell C, Wylfa Newydd, Oldbury B, Moorside, Bradwell B)

SYSTEM IMPACT: NO HINKLEY


AE

R T

em

pla

te 2

016a

13

Wholesale electricity prices are lower when Hinkley is replaced by wind or tidal, compared to CCGT


20

30

40

50

60

70

2015 2020 2025 2030 2035 2040

-£9/MWh

Tidal to replace HinkleyCCGT to replace Hinkley


Baseload electricity price,

£/MWh (real 2014)



AE

R T

em

pla

te 2

016a

14

There would be 3.8GW less CCGT on the system if tidal were to replace Hinkley, compared to wind replacing Hinkley



2 Others include all other renewables (biomass, solar, hydro and marine), nuclear and interconnector

Tidal provides significant amount of baseload generation, replacing the need for CCGT

On the other hand, wind still requires large amount of CCGT to provide reliable baseload generation

44.9 44.9 44.9

26.013.4

18.4

18.4

14.8

13.0

16.0

28.6

27.3

23.5

15.1 13.0

25.3

CCGT to

replace Hinkley

2.7 2.72.7

Wind to

replace Hinkley

3.7 0.0

2.8 0.0

3.6

Tidal to replace Hinkley

Installed capacity in 2035,

GWTidal

Battery Storage Wind onshore

Peaking

CCGT

Others

Pumped Storage

Wind offshore



AE

R T

em

pla

te 2

016a

15

Existing CCGTs also run fewer hours with more tidal and wind on the system



2 Others include all other renewables (biomass, solar, hydro and marine), nuclear and interconnector

100 109 116

8147

41

42

3244

114161 106

39

11

351

-2

7

CCGT to replace Hinkley

351


0


-1

352

8

0 -2

0

-1

0

Others

CCGT

Wind offshorePeaking

Pumped StorageWind onshoreTidal

Battery Storage

Power generation in 2035,

TWh



AE

R T

em

pla

te 2

016a

16

Replacing Hinkley with wind or tidal both require an additional £1.7bn in system spending, compared to CCGT


System spending1, 2030-2040 average

£ bn/year (real 2014)

4.5

+1.7+1.7


28.9

20.9


28.9

2.90.1 0.4

3.1

19.5

CCGT to replace Hinkley

0.9

27.23.1

6.4

21.3

1.7

ROCs Wholesale spending

CfDCapacity Market



AE

R T

em

pla

te 2

016a

17

Replacing Hinkley with tidal achieves a greater carbon reduction than replacing Hinkley with wind


4042

59

CCGT to replace Hinkley Wind to replace Hinkley Tidal to replace Hinkley

-17 -19

Average CO2 emission from 2030-2040 in UK power system,

MtCO2 per year



AE

R T

em

pla

te 2

016a

18

The cost of reducing carbon is thus £11/tonne cheaper with tidal replacing Hinkley, compared to wind


90

101

-10.2%

Wind to replace Hinkley Tidal to replace Hinkley

Average cost of carbon reduction from 2030-2040,

£/tonne



AE

R T

em

pla

te 2

016a


- Balancing market

- Cost of intermittency

Contents

3. Appendix



AE

R T

em

pla

te 2

016a

OTHER IMPACT: BALANCING MARKET

To give a complete assessment of tidal’s impact, we also consider the indirect costs


Direct costs to consumers Indirect costs

Wholesale market spending

Capacity market spending

ROCs spending

CfD spending

Balancing market spending

Intermittency costs

2nd Section1st Section


AE

R T

em

pla

te 2

016a

21

In section 2, we ran three scenarios to compare the impact of tidal and wind on the system


Scenario Description

Base caseAurora’s base case forecast (with Hinkley C)

No tidal to enter

Tidal 25.3GW of tidal by 2030

Wind 15GW1 of additional wind on the system by 2030

1. 25GW of tidal is required to achieve same annual production as 15GW of wind as tidal has an average load factor of 19% while wind has an average load factor of 30%



AE

R T

em

pla

te 2

016a

OTHER IMPACT: BALANCING MARKETTidal does not contribute to imbalance, but 15GW of wind increases imbalance volumes by 35% on average


180

215 215

435

180180

195195195

+34.9%

Base Tidal

630 630

850

Wind

4040 40

Demand

Solar

Thermal

WindAverage imbalance from 2030-2040

MWh


AE

R T

em

pla

te 2

016a


25GW of tidal requires on average £266million/year less BM spending, compared to having 15GW of wind


1 assuming all balancing costs are passed onto consumers and spread evenly across all units of consumption; calculated based on the following assumptions: 27 million households in UK by 2035 and 30% of total power consumption comes from domestic sector

355

Base

+244

599

-22

Tidal Wind

333

System spending on balancing market, 2030-2040 average

£ million/year (real 2014)

Additional cost to annual

household electricity bill1

- £0.30 £3.00


AE

R T

em

pla

te 2

016a


More batteries enter with tidal on the system, flattening cash-out prices


An additional 4.2GW of li-ion enters under the tidal scenario

Li-ion provides cheap balancing capacity and flattens the cash-out prices

Cash-out price

£/MWh

5.7

Base Wind

1.5

4.8

Tidal

+4.2

80

40

20

0

90

70

60

50

30

10

2040203020202015 2025 2035

TidalBase Wind

Li-ion capacity in 2035

GW

SHORT

LONG


AE

R T

em

pla

te 2

016a


- Balancing market spending

- Cost of intermittency

Contents

3. Appendix



AE

R T

em

pla

te 2

016a

26

Intermittent generators

create imbalance which

pushes up the cost of

demand (i.e. consumer)

imbalance


cannot be relied upon

during the winter peaks

and so additional

backup is needed from

the capacity market


may produce electricity

at periods of low

demand instead of

when consumers would

really benefit from it

(Note: this incorporates

‘spill’ costs)

To calculate the cost of intermittency, we look at the following 3 drivers


OTHER IMPACT: COST OF INTERMITTENCY

Poorly-timed

power

Need for

backup

Consumer

imbalance

cost

The cost of intermittency – the additional costs imposed on the energy system

resulting from the timing and predictability of a given generation technology’s

power output relative to a case where the same number of MWhs are generated

evenly over every hour of the year


AE

R T

em

pla

te 2

016a

27

Wind has a higher cost of intermittency than tidal, driven by its power coming at worse times


OTHER IMPACT: COST OF INTERMITTENCY

Tidal has a smaller cost of

intermittency due to poor

timing as it oscillates at a

reasonably constant

frequency and seems to

have some seasonal

variation that matches with

the electricity price

Intermittency cost from

consumer imbalance is also

smaller as tidal is more

predictable

However, tidal has a larger

CM cost of intermittency as:

1. It procures more

flexible capacity

2. It runs during the peaks

and so decrease the

profitability of CM

participants and raises

their CM bids

11.7

14.0

4.0

-1.7

Tidal

2.6

17.514.5

Poorly-

timed power

0.4

Consumer

imbalance

Need for

backup

Total

Wind

Cost of intermittency (average 2025-2040),

£/MWh production

Cost of intermittency (average 2025-2040),

£/MWh production


AE

R T

em

pla

te 2

016a

29

In practise we quantify the cost of intermittency by comparing intermittents to a baseload equivalent


1. 25GW of tidal is required to achieve same annual production as 15GW of wind as tidal has an average load factor of 19% while wind has an average load factor of 30%

APPENDIX: METHODOLOGY

Baseload

equivalent

Intermittent

generation

System has an additional

251 GW of tidal compared

to today’s levels

151 GW of wind compared

today’s levels

System has same annual

production from the

additional renewables

However, the MWh are

spread evenly throughout

year like nuclear

Our power market model allows us to

calculate the system wide effects of removing

the intermittency of wind and tidal, by running

two scenarios

Our model forecasts the electricity, capacity

and balancing markets in an internally

consistent way

Electricity

market

Capacity

market

Balancing

market

Half-hourly electricity prices

Consumer electricity spending

out until 2040

Annual generation mix

Capacity market prices and

bids consistent with other two

markets

Half-hourly cash-out prices

Charges for all imbalance

producing parties

Profits for thermal plants taking

part in the BM


AE

R T

em

pla

te 2

016a

30

We can compare the differences in consumer spending across the markets to calculate these costs



Electricity market Balanacing marketCapacity market System with

intermittent plant

System with

baseload plant

Other Capacity marketBalancing market Electricity marketCosts to the consumer, £/year

Costs of intermittency

ILLUSTRATIVE


AE

R T

em

pla

te 2

016a

31

Aurora has developed a comprehensive and internally consistent model for these markets



Energy Capacity

Balancing

Input assumptions

Technology

(capex,

performance,

learning rates)

Policy (changes

to existing

regulation,

renewables build

out, nuclear)

Fuel prices

Market outcomes

New build entry

and existing

decisions and

levels

Half hourly

electricity and

cash-out prices

Yearly capacity

market prices

Plant level

revenues

Entry and exit of every technology calculated, not assumed

Peaking plants

OCGTs

Gas recips

Embedded

Centralised

Diesel recips

Storage

Lithium ion

Paired with intermittent

Paired with domestic solar

Paired with industry

Paired with dispatchable

CAES

CCGT

Coal

DSR

Common process

Manufacturing processes

Inside of model Recalculated

thousands of

times to produce

internally

consistent solution

Forecasts rational

investor behaviour

for correct entry

and exit of plants

Decisions in each

market affect all

others correctly


AE

R T

em

pla

te 2

016a

32

There is cost of intermittency in the EM due to the steepness of the merit order at high demand levels



30

80

0

10

70

50

20

40

60

NuclearCCGTPeakers Coal Biomass

Generation

capacity, GWOvernight/summer

demand

Peak

demand

Electricity

price, £/MWh

20

10

0

40

50

30

70

80

60

A

B

C

D

Saving from a zero marginal cost unit of energy = A - B

Saving from a zero marginal cost unit of energy = C - D

A B

C D

Intermittent generation tends to occur in low demand periods (either overnight or during summer)

Baseload however hits both peak and off-peak periods equally

The cost of intermittency is this potential savings loss from these poorly placed MWhs

A B C D( – ) – ( – )

Cost of intermittency =


AE

R T

em

pla

te 2

016a

33

The cost of intermittency for the BM arises as intermittentsraise the cash-out price for everyone else as well


Intermittents create imbalance, increasing the need for balancing services…


…which raises cash-out prices above what they otherwise would have been…

…increasing the cost of imbalance for everyone else (so raising consumer bills)

Balancing offers, £/MWh

Imbalance in

baseload

scenario

Imbalance in

intermittent

scenario

The extra imbalance in this

half hour means more

expensive balancing offers

need to be taken

All imbalance is charged at

the clearing price (cash-out

price)

60

70

80

90

100

2020 2030 203520252015

Baseload equiv.

CCC wind targets

In early years, the system

doesn’t have chance to

adjust to the increased

balancing revenues

available

Cash out prices are

therefore higher on average

100

2025

20

0

2015

80

2030 2035

60

2020

40

Additional balancing spend, £mCash-out price (short), £/MWh

Every MWh of imbalance

from demand forecasting

error was previously at

lower cash-out prices

The additional imbalance

from intermittents may

increase this


AE

R T

em

pla

te 2

016a

34

The intermittent plant has the same load factor as its baseload equivalent, but needs more CM backup



While both plants have the

same load factor, the

baseload equivalent is de-

rated at its load factor, but

the intermittent plant far

less

This means more CM

capacity needs to be

procured for the intermittent

case

This extra spending is a

cost of intermittency

20

30

10

40

0

60

50

47

40

0

20

60

30

50

10

42

Other capacity needed to meet peak WindDemand in sample 3 days, GW

Time

Baseload

equivalent

Intermittent

generation


AE

R T

em

pla

te 2

016a

General Disclaimer

This document is provided “as is” for your information only and no representation or warranty, express or implied, is given by

Aurora Energy Research Limited (“Aurora”), its directors, employees, agents or affiliates (together its “Associates”) as to its

accuracy, reliability or completeness. Aurora and its Associates assume no responsibility, and accept no liability for, any loss

arising out of your use of this document. This document is not to be relied upon for any purpose or used in substitution for your

own independent investigations and sound judgment. The information contained in this document reflects our beliefs,

assumptions, intentions and expectations as of the date of this document and is subject to change. Aurora assumes no

obligation, and does not intend, to update this information.

Forward looking statements

This document contains forward-looking statements and information, which reflect Aurora’s current view with respect to future

events and financial performance. When used in this document, the words "believes", "expects", "plans", "may", "will", "would",

"could", "should", "anticipates", "estimates", "project", "intend" or "outlook" or other variations of these words or other similar

expressions are intended to identify forward-looking statements and information. Actual results may differ materially from the

expectations expressed or implied in the forward-looking statements as a result of known and unknown risks and uncertainties.

Known risks and uncertainties include but are not limited to: risks associated with political events in Europe and elsewhere,

contractual risks, creditworthiness of customers, performance of suppliers and management of plant and personnel; risk

associated with financial factors such as volatility in exchange rates, increases in interest rates, restrictions on access to

capital, and swings in global financial markets; risks associated with domestic and foreign government regulation, including

export controls and economic sanctions; and other risks, including litigation. The foregoing list of important factors is not

exhaustive.

Copyright

This document and its content (including, but not limited to, the text, images, graphics and illustrations) is the copyright material

of Aurora[, unless otherwise stated]. No part of this document may be copied, reproduced, distributed or in any way used for

commercial purposes without the prior written consent of Aurora.

Disclaimer

the impact of tidal lagoons on the gb power market · the impact of tidal lagoons on the gb power...

Documents