Version 1.0

EPOC Winter Workshop 2008:New Zealand Wind Integration Study

Goran Strbac, Danny Pudjianto, Anser Shakoor, Manuel J Castro

Imperial College London

Guy Waipara, Grant Telfar

Meridian Energy Limited

Sep 2008

Version 1.0

Background & motivation for NZ wind study

Anecdotes are not data

Assertion is not analysis

• Worldwide the rise of wind power has in the past and will continue into the future to present unique challenges to power system planning

• Motivation for NZ study was to inform and shape the debate in NZ to move beyond gut reaction and anecdote to develop methodologies and quantify – from first principals – what unique costs wind generation brings to the system

• Work first mooted in late 2005 and begun in earnest in May 2006 having first identified Prof Strbac as a expert in the integration of distribution generation into power systems.

• A desire to learn sometimes hard won lessons from other jurisdictions

• Explicit intent to focus on additional system operation costs due to wind NOT to focus on issues of market pricing, dynamic efficiency, …

• Place wind intermittency within the context of an imperfect power system

1

Challenges of integrating wind generation

• Generation capacity adequacy– How “reliable” is wind generation as a source? How much conventional capacity can it

displace? What are the system integration capacity costs and benefits? – Wind generation is primarily an energy source with limited ability to provide reliable generation

capacity at times of peak demand.

• Real time system balancing– What are the needs for flexibility and reserve? What are the costs? What is the role of storage,

demand side participation and inter-connectors?– Additional requirements for instantaneous and frequency keeping reserves.– Additional requirements for scheduling reserve.

• Transmission network requirements– How much new transmission capacity is required to efficiently transport wind power?

• System stability– What is stability performance of the system with new forms of generation? Can this technology

contribute to improving stability? • Role of enabling technologies

– Can storage and responsive demand have a role in facilitating integration of wind generation? Are these solutions competitive? What are the drivers of value? What new tools are required to support system management with wind generation?

• Technical, commercial and regulatory framework– Are the technical, commercial and regulatory arrangements appropriate for a system with

significant contribution of wind? Are the Grid Codes and Standards appropriate? Are the arrangements for access to transmission networks appropriate? Are non-network solutions to network problems competitive? Does the market reward flexibility adequately?

2

Future Generation Scenarios

NZ Electricity System: Future Scenarios• Three scenarios corresponding to future

generation snapshots in 2010, 2020 and 2030 were constructed to represent increasing levels of wind penetration:

– High Wind 2010: 2,100GWh (4.5%)• NI: 432 MW• SI: 203 MW• NZ: 634 MW

– Very High Wind 2020: 6,700GWh (12.5%)• NI: 1,434 MW• SI: 632 MW• NZ: 2,066 MW

– Very High Wind 2030: 10,700GWh (17.7%)• NI: 2,215 MW• SI: 1,197 MW• NZ: 3,412 MW

• Explicit intent to focus on system operation with and without wind at various points in time NOT to focus on issues of dynamic efficiency, etc:

– Of course not really that black and white in choice of scenario and implied counterfactual

3

Wind Profiles

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1 92 183 274 365

Dai

ly W

ind

Pow

er E

nerg

y (G

Wh)

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SI

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1 92 183 274 365D

aily

Win

d Po

wer

Ene

rgy

(GW

h)

Day

NZ

Wind (GWh) NI SI Total

Annual 1,653 631 2,285

Weekly maximum 49 24 72

Weekly minimum 15 2 20

Weekly average 32 12 44

2005 wind profiles for 2010 scenario


Annual 4,906 1,819 6,724





Annual 7,442 3,354 10,797




High Wind 2010 Very High Wind 2020 Very High Wind 2030

• Wind data profiles derived from:

– 10 minute real wind readings – mostly metering towers at 40m– 11 actual or proposed sites– Continuous 2 year period (Jan2005-Dec2006)

4

Scenario >> High Wind 2010 (4.9%) Very High Wind 2020 (12.5%) Very High Wind 2030 (17.9%)

Region >> NI SI NZ NI SI NZ NI SI NZ

Auxiliary 1,017 37 1,054 1,166 37 1,203 1,205 37 1,242

Wind 432 203 634 1,434 632 2,066 2,215 1,197 3,412

Hydro 1,873 3,557 5,430 1,873 3,557 5,430 1,873 3,557 5,430

Coal 972 - 972 972 - 972 972 - 972

Gas 1,500 - 1,500 1,570 - 1,570 1,810 - 1,810

Oil - - - - - - - - -

Distillate 156 - 156 156 - 156 156 - 156

Total capacity (MW) 5,949 3,797 9,747 7,171 4,226 11,397 8,230 4,791 13,022

Hydro energy (GWh) 6,919 17,929 24,848 6,919 17,929 24,848 6,919 17,929 24,848

Wind energy (GWh) 1,653 631 2,285 4,906 1,819 6,724 7,442 3,354 10,797

Peak demand (MW) 4,842 2,455 7,297 5,598 2,845 8,443 6,273 3,197 9,469

Energy demand (GWh) 28,952 17,041 45,993 33,644 19,812 53,456 37,907 22,351 60,258

Initial Electricity Generation and Demand Scenarios

Key Assumptions:

• Load & generation are defined at the “station gate” (including embedded)

• Annual demand growth is approximately 700GWh (110MW at peak)

• No decommissioning of existing assets (except New Plymouth PS)

• ‘Status quo’ fuel prices in perpetuity: gas = $6.5-7.5/GJ, coal = $4/GJ, distillate = $25/GJ

5

Capacity Value and Additional Capacity Cost of Wind Generation in the NZ Electricity System

Capacity Assessment Objectives

1. Assessment of ‘optimal’ overall generation capacity requirements in each future wind scenario

2. Capacity credit evaluation of wind generation

3. Evaluation of additional capacity cost of wind generation

4. Sensitivity Studies:

A. Wind forecasting errors

B. Impact of hydro conditions (Dry/Average/Wet)

C. Impact of inter-connector size and its reliability

D. Impact of wind diversity

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eman

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ower

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Hydro Wind Thermal Demand NI

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South Island

Hydro Wind Thermal Demand SI

Wind-Hydro-Thermal System

6

Capacity Assessment Formulation

• The system reliability criterion for capacity adequacy applied in this study is Loss of Load Expectation (LOLE) with a conservative target of 8 hours/year.

– Hydro is used to minimize overall thermal capacity requirements (ie the objective function)– Hydro is aggregated at the island level (with key catchment level constraints maintained)– Hydro is modelled as a fully reliable generation– Weekly reservoir energy releases (from Spectra) are used – water cannot be shared between weeks– Spare hydro capacity is available to contribute to system reliability

• Main constraints include:

– Aggregated (wind + hydro + thermal) production must meet demand in each time period– Minimization of wind and hydro energy curtailment– The aggregated reservoir size of each island for hydro energy storage– Minimum reservoir levels (10% of reservoir size)– 99% reliability of the DC inter-connector

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LOLP

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LOLP

2030: With Wind2030: Without Wind

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32 29

23

32 29

15

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2010 2020 2030

(% o

f win

d ca

paci

ty)

Scenario/Year

Capacity Credit of Wind

without forecasting errors

with forecasting errors

34 35

43

-

10

20

30

40

50

2010 2020 2030

(%)

Scenario/Year

Capacity Margin Requirements

System Capacity Margin Requirements & the Capacity Credit of Wind

Key assumptions:• Conservative system reliability criterion: LOLE < 8

hours/year

• Availability of conventional generation: 85% (planning time horizons)

• NI-SI Inter-connector reliability: 99%

• Wind forecasting approach is conservative & accommodates 99% of the wind variations across 4 to 6 hours time horizon.

8

Summary of Capacity Results• Additional capacity costs attributed to wind

generation

– Fall from 2010 to 2020 due to a larger HVDC size– Rise by 2030 due to reserve requirements to

accommodate larger wind forecasting errors

• Unlike peak focused thermal based power systems, the capacity value of wind in NZ is driven by its higher load factor as well as by large variations in a relatively small period of time

• Hydro increases capacity credit of wind however, but at higher penetration levels its contribution to firming up the wind power reduces

• Capacity credit of wind generation in the NZ’s hydro dominated system is higher than in the other thermal based systems, however, it also declines with rise in wind penetration level

• Capacity values for wind are not effected by hydro (dry) conditions although the overall capacity requirements increase with low availability of hydro energy

• The low production of wind for several days is found not to effect the capacity value of wind as this is compensated by the flexible hydro energy with presence of large hydro reservoirs

2.52.0

9.3

1.7 1.3

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2010 2020 2030

($/M

Wh

of w

ind)

Scenario / Year

Key Assumptions:• Capacity cost of (OCGT) conventional plant = 100 $/kW/yr to 150 $/kW/yr• The additional costs of wind are relative to a base load thermal plant

9

Cost of Wind Power Driven Reserve in the NZ Electricity System

Wind Reserve Requirement Objectives1. Quantify operating reserves needed to deal with wind intermittency and wind forecasting errors

A. Instantaneous reserve (up to 30 mins) provided by synchronised generatorsB. Frequency keeping reserve (up to 1 hour) provided by synchronised generatorsC. Scheduling reserve (for 4-6 hours) provided by synchronised and standing generators

2. Evaluate wind related impact of increased reserve requirement on system operating costs

A. Fuel cost, generation start up cost and no-load costB. Cost of interruptible load

3. Sensitivity analysis

A. Hydro conditions (Dry/Average/Wet)B. Increased wind power (scenario 2010,2020,2030)C. Inter-connector capacityD. Location of future wind power (North and Southland scenarios)E. Different wind profiles (year 2005 and 2006 data based)

10

Total Wind Portfolio Output & Deltas10 MinuteDate: Jan2005 to Dec2006

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prob MW >= X [%]

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ata

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Reserve Requirement Methodology• Additional reserves increase operating costs

– Requires more on-line capacity• Use of low merit (expensive) generation• Lower efficiency-part loaded plants

– Increased frequency of start-ups of generators– Increased demand of Interruptible load (IL)– Increased standing reserve

• Operating cost is determined using a MILP generation scheduling optimisation model for energy production and the allocation of reserves among synchronised units

– Objective• Minimise the total system generation costs (including no load, start up

cost and IL costs)

– Operational constraints• Power balance constraints• Generation constraints: Min stable generation, Power rating, Max

Instantaneous Reserve, Ramp up/down constraints, Min up/down time constraints, Load factor constraints for CCGTs (minimum 75%)

• Hydro catchment power constraints: Daily ROR energy constraints, Weekly hydro inflows constraints, Reservoir constraints

• Reserve constraints: Min instantaneous and frequency keeping reserve provision for each island (no reserves sharing)

• Flow constraints on HVDC

• Cost of additional operating reserve attributed to wind is determined as the difference between the operating cost of the system with and without wind reserve component

• Cost of standing reserve is determined by calculating the expected energy of standing reserve that would be exercised

11

North Island

South Island

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d Po

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er (M

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NI_Wind

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rve

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)Period

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SI_Wind

Amount of reserve requirements increases with increased wind

output

Reserve Requirements & Assumptions

Key Assumptions:• Additional operating reserves in each Island analysed separately, i.e. (no operating reserve sharing across the DC)• Power transfers across the DC link are limited by MW only (with the max of NI to SI level set to 60% of SI to NI)• All operating spinning reserves quantities for instantaneous reserve and frequency keeping are unable to meet demand requirements• Operating reserve mainly provided by part loaded plant along with a contribution from demand side (interruptible load)• Standing reserve is provided by off-line thermal plants which can synchronise and produce electricity quickly• Levels of operating reserve required cover about 99.5% of all operating conditions.• Reserve from synchronised plant are assessed at 30 min and 1 hour. Standing reserves deal with wind forecasting errors beyond 1 hour• Reserve requirements are computed for half-hourly. • Additional reserve requirements to deal with wind variability never exceed expected wind power output.• Day/night system inertia impacts on operating reserve requirements are modelled.• CCGTs assumed to operate with minimum load factor of 75% irrespective of hydro and wind conditions.

12

2010 2020 2030

IR FK Standing IR FK Standing IR FK Standing

Case 1 NI 398 107 124 446 215 312 533 315 503

SI 167 73 65 245 157 174 379 271 326

NZ 565 180 189 691 372 486 912 586 829

Case 2 NI 398 150 81 446 314 272 533 466 352

SI 167 93 31 245 226 105 379 400 214

NZ 565 243 112 691 540 377 912 866 566

Case 3 NI 398 194 37 446 416 170 533 618 200

SI 167 115 9 245 296 35 379 530 67

NZ 565 309 46 691 712 205 912 1148 267 Note: all units are expressed in MW• IR (Instantaneous Reserve)• FK (Frequency Keeping)

Case1: dominated by standing reserveCase2: balanced allocationCase3: dominated by spinning reserve

Summary of Reserve Requirements Results• Additional reserves are needed to cover the unpredictability of wind power:

– Instantaneous reserve provided by synchronised generators– Frequency keeping reserve to cover 1 h wind variability provided by synchronised reserve – Scheduled reserve to cover 4-6 h wind variability provided by synchronised + standing reserve

• The quantity of wind reserve component increases with rise in wind penetration

1.25

0.25 0.19

2.76

0.76 0.80

3.45

2.42

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2010 2020 2030

Annu

al C

ost o

f Win

d Re

serv

e Co

mpo

nent

($/M

Wh

of w

ind)

Annual Cost of Standing Reserve

Annual Cost of all Spinning Reserves

13

Case1: dominated by standing reserveCase2: balanced allocationCase3: dominated by spinning reserve

• Provision of scheduling reserve up to 4-6 hour time horizon

– For low wind penetration (2010), hydro will be the primary source

– For high wind penetration (2020 & 2030), it is desirable to use flexible standing power plants

• The cost of additional reserve to deal with forecasting error of wind for several scenarios have been quantified

– For low penetration (4.9% in 2010) , it is around 0.19 $/MWh of wind energy

– It increases to 2.42 $/MWh of wind energy in 2030 with high wind penetration (17.9%)

• Hydro remains the primary source of synchronized reserve, but in the future a greater contribution from IL and other thermal plants will be required

Summary of Findings

Summary of Key Results

19

2010 2020 2030

Installed wind power capacity (MW) 634 2,066 3,412

Wind power (GWh) 2,285 6,724 10,797

Capacity credit of wind (%) 32 29 15

Max. Instantaneous Reserve (MW) 565 691 912

Max. Frequency Keeping (MW) 309 540 866

Max. Standing Reserve (MW) 46 377 566

Capacity cost ($/MWh of wind) $1.7 - $2.5 $1.3 - $2.0 $6.2 - $9.3

Reserve cost ($/MWh of wind) $0.19 $0.76 $2.42

TOTAL Cost ($/MWh of wind) $1.9 - $2.7 $2.1 - $2.8 $8.6 - $11.7

14

Other Issues

Other Wind Related System Issues …• Quality of long-run wind record:

– Single biggest impediment to systematic analysis of wind– However good correlation (daily energy+) between synthetic

(NIWA weather station) data and actual wind farm data

• Annual wind variation:

– Positive correlation between wind and hydro may increase need for “hydro-firming” plant

– Not investigated here – but likely order of magnitude … small?:• A 30 year Spectra run with 8TWh of wind generates a total system

cost of $25B• Removing wind variation decreases market prices by $2/MWh (2%)

and system costs by $63M (0.3%)

15

Wind Portfolio Energy Production

5500

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ann

ual

en

erg

y p

rod

uct

ion

[G

Wh

]

Annual Energy Avg: 6854.1GWh

Calendar Year Output: 1990-2007

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Spread: 86%-111%

Avg: 6854.1 GWh

Total Wind Energy Correlation With Total Hydro Inflow Energy

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Wind (2.2GW) and NZ Peak Load Correlation

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NZ Load

01-Jan-2005 to 31-Dec-2006 : 30 Min Intervals

• Correlation between demand and wind:

– Positive correlation between extreme peak demand and low wind conditions may reduce capacity credit of wind and increase need for additional ‘firm’ system MW

2006 Calendar Year

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