Wind in Ireland Integration and cost issues David Milborrow [email protected].

Wind in Ireland

Integration and cost issues

David [email protected]

om

Author’s previous encounters in Ireland

•Participated with ESB and other EU utilities in EC-funded studies of wind impacts c.1988

•Member of Advisory Panel which selected turbines for Bellacorick, 1990/91

• Invited speaker at IWEA Conference, 1996

•Adviser to developer based in Co Cork on several windfarms (some now built) since 1994

•No permanent affiliations!

Scope of talk

•Assimilating wind Issues? Problems? Costs? Limits?

•Extra costs to consumers of adding wind Sensitivities?

Very brief economic interlude

•Much interest in “Extra cost of renewables”

• Justified by “External costs” of thermal sources, esp Global Warming

Wind and the competition

PUBLIC SECTORWind

OffshoreGasCoal

NuclearPRIVATE SECTOR

WindOffshore

GasCoal

Nuclear

0 20 40 60 80 100Generation cost, US$/MWh

MinimumRange

Source: Author, Windpower Monthly, January 2004

Levelling the playing field

•Generation cost comparisons not the whole story

•Value of wind = Fuel saving value + CAPACITY SAVING

value + “embedded benefits” + “green value” - costs of backup

•Embedded benefits may be positive or negative

Who has looked at integration issues?

• Ireland ESB (1990), CEGB, and other EU utilities, as part of

co-ordinated study IWEA, “Geographical dispersion of wind in Ireland”,

1999 Garrad Hassan “Impacts” study, 2003 University College, Dublin

• UK DTI/Carbon Trust Network Study, Intermittency Module, has c.40 worldwide refs back to 1980

• Grid operators: Eltra, NGT, Nordel, and US utilities

Ireland is different

•Could be first self-contained electricity system to operate with significant wind input Denmark is not isolated, but source of

useful data, as W Denmark system similar in size

W Denmark currently runs with wind supplying ~20% of consumption

Ties with neighbours mean that effective wind supply is about 10% - still respectable!

Integration topics

•Electricity networks

•Behaviour of wind plant

•Assimilating wind into networks Storage Capacity credit

•Transmission issues

•The future

Electricity systems

Why integrated systems?

• Smoothing Demands Generation sources

• Peak/average House: 15 UK: 1.5

• Lower plant margins needed - House: at least 2*peak

• Large electricity system: ~1.2* peak• All leads to LEAST COSTS

Benefits of integrated systems

1 10 100 1,000 10,000 100,0001

1.4

2

3

4

6

8

10

Average demand, MW

Peak demand/average; plant needs/average

Plant

Peak

Lessons from western Denmark

0 50 100 150 2001,500

2,000

2,500

3,000

3,500

4,000

4,500

Time in hours from 1.2.04, 00:00

System demand, MW

EI

DK

Scheduling errors

Source: Electricity PoolStandard deviation: 1.6%

0 5 10 15 20 25 30-4

-3

-2

-1

0

1

2

3

4

Day of month (November 1995)

Scheduling error, %

Coping with demand variations

•Generator inertia

•Frequency & voltage changes

•Demand management

•Pumped storage

•Spinning reserve

•All can cope with demand increase or decrease

Wind characteristics

Smoothing makes a difference

0 5 10 15 200

200

400

600

800

1,000

Time, hours

Wind output, MW

Singlefarm

Distributedfarms

Smoothing of power swings

-100 -50 0 50 100

0.01

0.1

1

10

Change, % rated capacity

Time, %

1 farm

WesternDenmark

Time interval: 1 hour

Impacts of 20% wind

-400 -200 0 200 400 600 8000.03

0.1

0.3

1

3

10

30

Intra-hourly load change, MW

Time, %

Demand- wind

Demand

Running electricity systems

•Managing electricity systems is all about managing risks

•All estimates of uncertainty come with a range of probabilities, and

•Uncertainty margins do not add arithmetically – a “sum of squares” law applies

Estimating the effects of wind

•Establish “demand prediction error” for electricity system UK system, 1 hour ahead, ~ 1.3%, or 400 MW Irish system: similar %, ~40 MW

•Estimate “demand prediction” error for wind Typically ~3% standard error for distributed

wind, 1 hour ahead, (“persistence” forecast)

•Error with wind, based on “sum of squares”

Costing the effects of wind

•Scheduling error with wind enables extra reserve capacity needs to be estimated

•Establish cost of extra reserve, based on Reduced efficiency of part-loaded plant Cost of plant, or, Market rates

Extra back-up capacity

0 10 20 30 40 500

2

4

6

8

10

Wind capacity/peak demand, %

Back-up capacity/wind capacity, %

Ireland(Doherty)

NRELPersistence

Perfect

US (BPA)

AuthorUpper

Lower

Extra costs for backup

0 2 4 6 8 100

1

2

3

4

5

Wind Energy penetration, %

Cost of extra balancing, $/MWh

UKNGC

Ilex

PacifiCorp

BPAMax

Min

EPRI/Xcel et al

Storage

•"Renewables need storage" ? Rather misleading!

•Only the intermittent sources

•"Storage can transform the economics of the intermittent renewables" ?

•Only if they are very low cost!

•Several studies have concluded that economics must be studied separately; may be useful to system, or as reserve

Capacity credits

The “Firm power” issue

+ + =

?

Capacity credits

•Controversial, despite -

•Most authoritative studies confirm wind HAS a capacity credit. Includes Ireland

•Note that definitions a muddle Some refer to firm power, some to thermal

plant Firm power is less than rated capacity – For ALL types of plant!!

Evaluating capacity credits

•2 basic methods:-

•Establish system LOLP - usually over a year

•Add wind

•Subtract firm power to restore original LOLP

•Or (simplified approach, essentially similar)

•Examine availability of wind at time(s) of peak demand

Capacity credits depend on:-

•Amount of wind on system

•Wind speeds

•Wind turbine types

•Winds at time of peak demand

•Utility operating procedures

When “normalised” for differences in wind speed, good agreement between most estimates for northern Europe

Capacity credits – EU studies

2 4 6 8 10 12 14 160

0.1

0.2

0.3

0.4

Energy penetration, %

Capacity credit/rated power

DE DK ES F GR IR IT NL P UK

Capacity credits for Ireland

0 5 10 15

0.4

0.6

0.8

1

1.2

1.4

Wind energy penetration, %

Capacity credit/annual capacity factor

ESB, 19904 sites

1 site

UK

ESB, 2004

Capacity credits: monetary values

•These depend on:-

•Alternative thermal plant

•Test discount rates and depreciation times

•CCGT plant now most common thermal option in EU, costs €500-800/kW

•Capacity valued at €42-83/kW

•No "universal" value

Benefits of distributed generation

•Reduced losses• Improved reliability, + technical issues•Reduced costs if line reinforcements can

be deferred or forgotten

BUT•Siting is important•too much DG in remote areas will increase

losses•or may advance need for line

reinforcements

Local issues

•Analysis of Delabole wind farm (UK) by SWEB showed:- No problems with flicker Peak demands at local substation

coincided with peak output from wind farm Wind farm output "has major influence in

stabilising the 11 kV voltage level"

•Analysis by P G & E also showed benefits from PV installation

Wind integration – conclusions

•Modest costs for extra reserve Most studies yield similar results

•Capacity credits? – Yes, roughly=average power

•Problem areas? May be preferable, once wind input exceeds

~10%, to curtail wind output on a few occasions

•…..but wind will NEVER impose “jolts” on the system comparable with loss of a circuit of cross-channel link

Carbon savings from renewables

• Variety of answers in literature:- Due to average emissions from plant mix Due to gas plant which will not be built Due to emissions from load following (lf) plant

• In daily operations, wind displaces lf plant

• New renewables build forces closure of old thermal (usually coal) plant, just as new gas

• Gas plant not built? How can you be sure?

• So another argument in favour of 600-850g/kWh from closure of old coal (or oil) plant

Extra costs of renewables

• Increasing interest in “extra costs” as States define renewable targets

•Estimates of extra costs from various sources

•Author linked to estimate in Power UK, issue 109: ~0.3p/kWh to consumer bills for 20% wind by 2020

•Key issues: Gas prices by 2020Wind plant costsPrice of carbon under ETS

Possible future Irish scenarios

System MW

5000 5000 5000 6500 6500 6500

Wind % 5 10 16 12 20 27

Wind MW

500 1000 1500 1500 2500 3500

Offshore %

25 30 40 40 45 50

Date 2005 2008 2010 2010 2017 2025

Source of base data (green): ESBNG; author’s assumptions in red

Future gas prices

Source: US DoE, Annual Energy Outlook, 2004

2000 2005 2010 2015 2020 202512

14

16

18

20

22

Year

Gas price to electricity generators, $/MWh

Future wind prices

2000 2005 2010 2015 2020400

500

600

700

800

900

1,000

1,100

Year

Installed price, $/kW

IOWAReference

Low

Trendscontinue

DEWI

REPP

EWEA

Possible costs to electricity consumers of

adding wind

US DoE gas price trendsNo allowance for costs under ETS

2005 2010 2015 2020 2025-0.6

-0.4

-0.2

0

0.2

0.4

0.6

0.8

1

Year

Extra cost, €/MWh

Thank you!

The End