Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources

SCENARIOS FOR DE INVESTMENT AS AN ALTERNATIVE TO LINES UPGRADES

– RURAL CASE STUDIES

12th Feb 2007

Sustainable Innovative Solutions Ltd.

Dr. Iain Sanders

2

Summary

This study considers the value of Distributed Energy (DE) in deferring or eliminating line capacity-based upgrades.

It assumes a combination of fuel-based DE, e.g. diesel gensets or fuel cells in combination with intermittent Renewable Energy (RE) to ensure that normal supply reliability can be delivered at all times.

Both the value and costs of the combinations are clearly identified.

The net results are almost always positive in comparison with line upgrades for capacity reasons.

3

MainPower Lyndon (ML) line



Predicted Load Duration Curve

TypicalExample

2003 Load Duration Curve for Lyndon Line

0

10

20

30

40

50

60

70

80

90

1001

227

454

680

907

1133

1360

1586

1813

2039

2266

2492

2719

2945

3172

3398

3625

3851

4078

4304

4531

4757

4984

5210

5437

5663

5890

6116

6343

6569

6796

7022

7249

7475

7702

7928

8155

8381

8608

Cummulative Hours of the Year

Cap

acity

(kW

) 60kW BASE-CASE USED FOR LOAD DURATION PROJECTIONS

80kW MAXIMUM STANDARD OPERATING CAPACITY THRESHOLD


0

10

20

30

40

50

60

70

80

90

1001

227

454

680

907

1133

1360

1586

1813

2039

2266

2492

2719

2945

3172

3398

3625

3851

4078

4304

4531

4757

4984

5210

5437

5663

5890

6116

6343

6569

6796

7022

7249

7475

7702

7928

8155

8381

8608


Cap

acity

(kW



Firm DE


0

10

20

30

40

50

60

70

80

90

1001

227

454

680

907

1133

1360

1586

1813

2039

2266

2492

2719

2945

3172

3398

3625

3851

4078

4304

4531

4757

4984

5210

5437

5663

5890

6116

6343

6569

6796

7022

7249

7475

7702

7928

8155

8381

8608


Cap

acity

(kW




0

10

20

30

40

50

60

70

80

90

1001

227

454

680

907

1133

1360

1586

1813

2039

2266

2492

2719

2945

3172

3398

3625

3851

4078

4304

4531

4757

4984

5210

5437

5663

5890

6116

6343

6569

6796

7022

7249

7475

7702

7928

8155

8381

8608


Cap

acity

(kW



Firm DE

What is Line Upgrade Deferral?

Primary objective for DE to meet peak load requirements

4

Using integrated distributed energy technologies, some technologies may be owned & controlled by the networks, and some technologies may be owned & controlled by the customers

C u sto m e r E ff ic ie n cy

C e n tr a l G e n e r a tio n

T o d a y 's T o d a y 's C en tr a l U tilityC e n tr a l U tility

T o m o rro w 's T o m o r ro w 's D is tr ib u ted U tility ?D is tr ib u ted U tility ?

R e m o teL o a d s

W in d

P V

G e n se t

F u e l C e ll

B a tte r y

C u sto m e r s

C e n tr a l G e n e r a tio n

© 2 0 0 2 D is tr ib u te d U til ity A sso c ia te s1

M ic r o tu r b in e

Can Costly Upgrades Be Prevented? 15

C u sto m e r E ff ic ie n cy

C en tr a l G e n e r a tio n

T o d a y 's T o d a y 's C e n tr a l U tilityC e n tr a l U tility

T o m o r ro w 's T o m o r ro w 's D is tr ib u ted U tility ?D is tr ib u ted U tility ?

R em o teL o a d s

W in d

P V

G e n se t

F u e l C e ll

B a tte r y

C u sto m e r s

C en tr a l G e n e ra tio n

© 2 0 0 2 D is tr ib u te d U til ity A sso c ia te s1

M ic r o tu r b in e

5

Distributed Energy Benefits

Support adoption of environmentally friendly alternatives, providing carbon credits.

Provide supplementary revenue to farmers. Remove burden of costly infrastructure upgrades on tax-

/rate-payers. Reduce risk of failure of over-loaded transmission &

distribution lines. Promote energy-efficiency and development of alternative

energy resources. Only pay for what is required using modular distributed

energy (DE) technologies. Provide additional revenue / savings for network operators

6

Motivation for Research It is getting harder for Networks to cover O&M and

replacement costs on infrastructure: Increasing population hot spots increase rural demand putting

pressure on existing rural networks Most rural network infrastructure is old, nearing the end of its normal

life, making O&M costly and in urgent need of replacement Preventive O&M is no longer affordable, resulting in more severe and

costly failures when they happen New Zealand is rich in alternative energy resources which

could make a substantial contribution only through these techniques

Local communities are keen to develop natural resources for long-term sustainable development of the region

Potential for DE technology to reduce peak demand and therefore extend the life of the ageing network infrastructure

Opportunities for islanded operations to deliver higher reliability at lower service costs – self-healing / interactive microgrids

7

Network asset data provided by:

Eastland NetworksMainPowerOrion Networks

These organisationswere closely involvedwith deriving the costingmodels and economicanalysis methodologies

8

Main Case Study – a section of the Eastland Network was chosen –

The Ruatoria 11kV Feeder from the Ruatoria 50/11kV Substation

Main Case Study – a section of the Eastland Network was chosen –

The Ruatoria 11kV Feeder from the Ruatoria 50/11kV Substation

Eastland Network

Te Puia is fed from

Tokomaru Bay

50/11kV line

TOLAGA BAYINPORT

TOKOMARU BAY INPORT

RUATORIA INPORT

TE ARAROAINPORT

GISBORNEINPORT

Te Puia is fed from

Tokomaru Bay

50/11kV line

TOLAGA BAYINPORT

TOKOMARU BAY INPORT

RUATORIA INPORT

TE ARAROAINPORT

GISBORNEINPORT

FOCUS

9

Ruatoria Feeder Profile Trends

10

Ruatoria Feeder Growth Scenarios Explored• Actual growth rate = 1.5% per year

• To illustrate impact of DE, growth projections of:

1.75, 5 & 10% per year were investigated

• Peak load capacity threshold of 1600kW

selected to illustrate method

• Threshold represents capacity

above which line is overloaded

11

Ruatoria Load Growth ScenarioAverage Load Versus Peak Load for 10% Load Growth of Ruatoria Feeder

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Year

Tota

l Loa

d (k

W)

Average (kW)Maximum (kW)

Threshold (kW)

Peak load DE requirementPeak load DE requirement

12

Direct & Indirect Annual O&M Costs (Derived from Asset Management Plan and Asset Accounting Spreadsheets)

Direct Costs = $935 / km / Year Indirect Costs = $66 / Connection / Year

Hypothetical cost of reinvestment once existing infrastructure is replaced Annual reinvestment cost = {ODRC x 2} / 40 (lifetime) ODRC = Optimized Depreciation Replacement Cost

333No. of Connections

$40,678.0020.000Ruatoria: H. RuatoriaAnnual O&M CostsLength (km)FEEDER

333No. of Connections

$40,678.0020.000Ruatoria: H. RuatoriaAnnual O&M CostsLength (km)FEEDER

Total Return = Annual O&M Costs + Annual Reinvestment

$40,678.00Annual O&M Costs

$74,028.00$33,350Ruatoria: H. RuatoriaTotal Annual RequiredReinvestment / Yr.FEEDER

$40,678.00Annual O&M Costs

$74,028.00$33,350Ruatoria: H. RuatoriaTotal Annual RequiredReinvestment / Yr.FEEDER

13

Grid Upgrade Deferral Assumptions for 10% Growth Rate

Note(1): Planning Horizon = Furthest Extent of Asset Investment (max. = 100).Note(2): Deferral time = Duration of DER project (1 to 30 years (max)).

Parameters Variable UnitsFeeder Capacity Threshold, C(T) 1,600.0 kWNetwork Finite Planning Horizon, n 40.0 years Note(1)(Max.) Network Investment Deferral Time, Dt 20.0 years Note(2)Utility Cost of Capital (Borrowing), r 10.0% as shownInflation Rate Net of Technology Progress, i 3.0% as shownCapacity Deferred By Dt Years 6,473.0 kWPW Marginal Distribution Capacity Cost, MDCC $739,063.44 as shownPW MDCC ($/kW/Yr) $99.37 $/kW/YrPW MDCC ($/kWh/Yr) $0.0807 $/kWh/Yr

To illustrate the methodology and impacts, the 10% loadgrowth rate scenario is chosen in this presentation

14

Assumed DE Capital CostsHydro & Wind Capital Cost: O&M = 2% of Capital Cost / YearPV & SHW Capital Cost: O&M = 0.5% of Capital Cost / Year

Diesel Genset Capital Cost: O&M = 5% of Capital Cost / Year

$100

$1,000

$10,000

$100,000

0 1 10 100 1,000 10,000

Size, kW

Cap

ital C

ost,

$/kW

HydroWindPhotovoltaicSolar Hot WaterGensetLog. (Photovoltaic)Log. (Hydro)Log. (Wind)Log. (Solar Hot Water)Log. (Genset)

15

Inputs to the Model:RE Supply Profiles are required

Higher the detail, the better the accuracy of the costs predicted

Supply factor curves, derived from recorded time sequence data

Local DE supply is used to support capacity shortfall in the distribution system

RE is the preferred local DE supply option to make up the peak load shortfall, with fueled DG (e.g. diesel genset) making up the balance

16

Flow-of-River Hydro Electric Power

1815

2229

3643

5057

6471

7885

9299

106113

120127

134141

148155

162169

176

0:30 2:00 3:30 5:00 6:30 8:00 9:30

11:0

0

12:3

0

14:0

0

15:3

0

17:0

0

18:3

0

20:0

0

21:3

0

23:0

0

0

200

400

600

800

1,000

1,200

Flow

(m3/

s)

Day of Year /...

Time of Day

1/2 Hourly Water Flow (in cubic metres per second) for an Actual River for Day 1 to 182 of a Normal Calendar Year

0.00-200.00 200.00-400.00400.00-600.00 600.00-800.00800.00-1000.00 1000.00-1200.00

17

HEP Supply Factor for RiverflowHEP Supply Curve

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

0.800

0.900

1.000

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Percentage of Max. Capacity Available

Supp

ly F

acto

r (A

vera

ge D

eliv

ered

/Tur

bine

Rat

ing)

18

Wind Turbine Generator (WTG) Half-Hourly Profiles

1815

2229

3643

5057

6471

7885

9299

106113

120127

134141

148155

162169

176

0:30 2:00 3:30

5:00 6:30 8:00 9:30

11:0

0

12:3

0

14:0

0

15:3

0

17:0

0

18:3

0

20:0

0

21:3

0

23:0

0

0100200

300400500

600700800

9001000

1100

Cap

acity

(kW

)

Time of Day

1/2 Hourly Load Profile for 1 MW WTG for Day 1 to 182 of a Normal Calendar Year (Annual Wind Speed = 6m/s)

0-100 100-200 200-300 300-400400-500 500-600 600-700 700-800800-900 900-1000 1000-1100

19

Photovoltaic Half-Hourly Profiles

1815

2229

3643

5057

6471

7885

9299

106113

120127

134141

148155

162169

176

0:30 2:00 3:30 5:00 6:30 8:00 9:30

11:0

0

12:3

0

14:0

0

15:3

0

17:0

0

18:3

0

20:0

0

21:3

0

23:0

0

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

Cap

acity

(kW

)

Time of Day

1/2 Hourly Load Profile for 1 kW PV System for Day 1 to 182 of a Normal Calendar Year

0.00-0.10 0.10-0.20 0.20-0.30 0.30-0.400.40-0.50 0.50-0.60 0.60-0.70 0.70-0.800.80-0.90 0.90-1.00

20

Solar Hot Water Contribution to Electrical Heating Demand

0:001:00

2:003:00

4:005:00

6:007:00

8:009:00

10:0011:00

12:0013:00

14:0015:00

16:0017:00

18:0019:00

20:0021:00

22:00

23:00

0

0.5

1

1.5

2

kW E

lect

rical

Hot

W

ater

Equ

ival

entTime of Day

Month of Year

Heating Profiles Contributed by a 4m2 Solar Hot Water System

0-0.5 0.5-1

1-1.5 1.5-2

The Solar Hot Water profile is significantly different to the PV profile because it is assumed that electrical water heating (the load that is replaced by SHW) takes place during the off-peak period: 11pm to 7am (used in ripple-relay control of domestic water cylinders (boilers) in many parts of NZ.

21

Results: Net DE Cost-Benefit

Total costs – capital investments, maintenance, operating costs and fuel costs etc., calculated as a net present value (NPV) for both the renewable and fuel-based DE options.

Total benefits – line upgrade deferral, transmission savings, grid-supporting and non-grid energy production less loss of distribution earnings to the network from using local energy, calculated as a NPV for both renewables and fuel-based DE.

NPVs calculated over a 20-year project lifecycle, assuming a 10% utility cost of capital interest rate, and a 3% inflation rate net of technology progress.

22

RE-Genset Cost-Benefit AnalysisComparison of Net-Benefits and Net-Costs from Various RE-Genset Combinations

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

$10,000,000

20Gen

/80Hyd

ro B

enefit

20Gen

/80Hyd

ro C

ost

20Gen

/80W

ind Ben

efit

20Gen

/80W

ind Cos

t

20Gen

/80PV B

enefit

20Gen

/80PV C

ost

20Gen

/80SHW

Ben

efit

20Gen

/80SHW

Cos

t

50Gen

/50Hyd

ro B

enefit

50Gen

/50Hyd

ro C

ost

50Gen

/50W

ind Ben

efit

50Gen

/50W

ind Cos

t

50Gen

/50PV B

enefit

50Gen

/50PV C

ost

50Gen

/50SHW

Ben

efit

50Gen

/50SHW

Cos

t

80Gen

/20Hyd

ro B

enefit

80Gen

/20Hyd

ro C

ost

80Gen

/20W

ind Ben

efit

80Gen

/20W

ind Cos

t

80Gen

/20PV B

enefit

80Gen

/20PV C

ost

80Gen

/20SHW

Ben

efit

80Gen

/20SHW

Cos

t

100G

en B

enefi

t

100G

en C

ost

RE-Genset Combination

NPV

of B

enef

it / C

ost

Renewable Benefit – Cost of distribution revenue loss

Genset Benefit – Cost of distribution revenue loss

Renewable Cost

Genset Cost

23

RE-Genset Cost-Benefit AnalysisAnnualised Return on Investment (ROI) from Investing in Different RE-Genset Combinations

-2.0%

-1.0%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

10.0%

20Gen/80Hydro Benefit

20Gen/80Wind Benefit

20Gen/80PV Benefit

20Gen/80SHW Benefit



50Gen/50PV Benefit

50Gen/50SHW Benefit



80Gen/20PV Benefit

80Gen/20SHW Benefit

100Gen Benefit


RO

I / Y

r, A

nnua

lised

ove

r 20

Year

s (%

)

Net Cost

Net Benefit

24

R.E. Only Cost-Benefit for Different RatiosNet RE Cost-Benefit from Different Renewable Ratios in the Genset-Renewable DE Mix

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

Percentage of Renewable Present

Net

Cos

t-Ben

efit

in N

PV (O

ver 2

0 Ye

ars)

Hydro-BenefitWind-BenefitPV-BenefitSHW-BenefitHydro-CostWind-CostPV-CostSHW-Cost

Benefit

Cost

Benefit

Cost

25

Total D.E. Cost-Benefit for Different Ratios

Net DE [RE+Genset] Cost-Benefit from Different Renewable Ratios in the Genset-Renewable DE Mix

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

$10,000,000

$11,000,000

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

Percentage of Renewable Present

Net

Cos

t-Ben

efit

in N

PV (O

ver 2

0 Ye

ars)

Hydro-DE CostWind-DE CostPV-DE CostSHW-DE CostHydro-BenefitWind-BenefitPV-BenefitSHW-Benefit

Benefit

Cost

Benefit

Cost

26

Line Upgrade Deferral Valuation Methodologies Used

Two different methods were used to calculate the value provided by deferring line upgrades for capacity reasons.

Both methods calculated the network capacity requirements from D.E. for every half-hour over a 20-yr lifetime.

Capacity valuation is based on the peak (maximum) capacity delivered by D.E. each year (benefits fuel-driven D.E. systems).

Energy valuation is based on the total (sum) energy delivered by D.E. each year (benefits R.E.-driven D.E. systems).

Net Present Valuation (NPV) of Capacity is greater in the early years, while NPV of Energy is greater in the latter years.

Overall, the energy NPV over the 20-yr project lifetime is greater than the capacity NPV.

27

Comparison of kW- vs. kWh-driven Support

Comparison of Net Benefit from Capacity-Driven vs. Energy-Driven Line Upgrade Deferral

-$2,000,000

-$1,000,000

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

kW-Focus kWh-Focus

NPV

for L

ifetim

e Be

nefit

Disc. Distribution (kWh)

Disc. Grid-Supporting Energy (kWh)Disc. Trans. Saving (kW)Disc. Upgrade Deferral (kW)

Line upgrade deferral value based on kW capacity valuation methodology

Line upgrade deferral value based on kWh energy valuation methodology

Relates to energy supplied only during peak

periods related to grid-support

Distribution feeder peak load

reduction corresponding to

GXP peak load reduction

Distribution revenue lost

Peak period kW capacity valuation for line

upgrade deferral

Peak period kWh

energy valuation for line

upgrade deferral

28

Key Points Identified

Despite greater discounting of long-term capacity / energy benefits, the overall (summation) financial benefit of discounted kWh energy valuation methodology is greater than the discounted kW capacity valuation methodology.

This implies minimum-cost to network-operated DE with capacity-driven valuation (e.g. large-scale DE with Orion).

This implies maximum-benefit to customer-operated DE with energy-driven valuation (e.g. small-scale DE with Orion).

29

Energy NPV Time-series for Line Upgrade Deferral

NPV of energy delivered for line upgrade deferral, transmission savings at GXP, wholesale energy sold (providing grid-support) and loss of distribution earnings were calculated and compared for each year, using 100% diesel genset D.E. as the base-case.

Other D.E. systems with a renewable energy component, also include NPV of surplus wholesale energy sold and loss of distribution earnings, notrelated to line upgrade deferral.

30

100/0% Genset-RE DE AnalysisLine Upgrade Deferral Met By 100% Genset and 0% Renewable (RE)

-$200,000

-$100,000

$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

$1,100,000

$1,200,000

$1,300,000

$1,400,000

$1,500,000

$1,600,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

No. of Years Line Upgrade Deferred

Net P

rese

nt V

alue

of N

et A

nnua

l DE

Bene

fit

Gen Distribution Loss (kWh)Gen Grid-Supporting Energy (kWh)

Gen Trans. Saving (kW)Gen Upgrade Deferral (kWh)

Peak period kWh energy valuation for line upgrade

deferral

Example: 50/50% Fuel-Driven Diesel Genset-Renewable DE Ratio

• A comparison of different renewable

to fuel-driven (diesel) genset ratios

was made: 0/100%, 20/80%,

50/50% and 80/20% based upon the

actual kW sizing (name-plate) of

the individual DE systems.

The annual installation of

D.E. capacity matches the

shortfall in distribution

system capacity.

32

50/50% Genset-Hydro DE AnalysisLine Upgrade Deferral Met By 50% Genset and 50% Hydro DE

-$200,000

-$100,000

$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

$1,100,000

$1,200,000

$1,300,000

$1,400,000

$1,500,000

$1,600,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20


Net P

rese

nt V

alue

of N

et A

nnua

l DE

Bene

fit

RE Non-Grid-Supporting Energy (kWh)Gen Distribution Loss (kWh)

RE Distribution Loss (kWh)Gen Grid-Supporting Energy (kWh)

RE Grid-Supporting Energy (kWh)

Gen Trans. Saving (kW)RE Trans. Saving (kW)Gen Upgrade Deferral (kWh)

RE Upgrade Deferral (kWh)

33

50/50% Genset-Wind DE Analysis Line Upgrade Deferral Met By 50% Genset and 50% WTG DE

-$200,000

-$100,000

$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

$1,100,000

$1,200,000

$1,300,000

$1,400,000

$1,500,000

$1,600,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20


Net P

rese

nt V

alue

of N

et A

nnua

l DE

Bene

fit






34

50/50% Genset-PV DE AnalysisLine Upgrade Deferral Met By 50% Genset and 50% PV DE

-$200,000

-$100,000

$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

$1,100,000

$1,200,000

$1,300,000

$1,400,000

$1,500,000

$1,600,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20


Net P

rese

nt V

alue

of N

et A

nnua

l DE

Bene

fit






35

50/50% Genset-SHW DE AnalysisLine Upgrade Deferral Met By 50% Genset and 50% SHW DE

-$200,000

-$100,000

$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

$1,100,000

$1,200,000

$1,300,000

$1,400,000

$1,500,000

$1,600,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20


Net P

rese

nt V

alue

of N

et A

nnua

l DE

Bene

fit






Influence of Carbon Tax and Fuel Costs on Diesel Price

• Base-case assumes an annual increase of 2% / year in the

price of diesel, with a starting price of: $1.00 / litre.

• More dramatic (exaggerated) fuel price increases of:

5 & 10% / year are included to account for

potential scarcity of fuel at some

future date.

• Initial fuel starting prices of $1.50

& $2.00 / litre are also considered

to account for potential carbon taxing.

(Fuel price includes an assumed carbon tax component).

37

Comparison of Net-Benefits and Net-Costs from Various RE-Genset Combinations

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

$10,000,000

20Gen

/80Hyd

ro B

enefit

20Gen

/80Hyd

ro C

ost

20Gen

/80W

ind Ben

efit

20Gen

/80W

ind Cos

t

20Gen

/80PV B

enefit

20Gen

/80PV C

ost

20Gen

/80SHW

Ben

efit

20Gen

/80SHW

Cos

t

50Gen

/50Hyd

ro B

enefit

50Gen

/50Hyd

ro C

ost

50Gen

/50W

ind Ben

efit

50Gen

/50W

ind Cos

t

50Gen

/50PV B

enefit

50Gen

/50PV C

ost

50Gen

/50SHW

Ben

efit

50Gen

/50SHW

Cos

t

80Gen

/20Hyd

ro B

enefit

80Gen

/20Hyd

ro C

ost

80Gen

/20W

ind Ben

efit

80Gen

/20W

ind Cos

t

80Gen

/20PV B

enefit

80Gen

/20PV C

ost

80Gen

/20SHW

Ben

efit

80Gen

/20SHW

Cos

t

100G

en B

enefi

t

100G

en C

ost


NPV

of B

enef

it / C

ost

Renewable Benefit – Cost of distribution revenue loss

Genset Benefit – Cost of distribution revenue loss

Renewable Cost

Genset Cost

Base Case: $1.00/l inc. at 2%/yr

38

Starting Price: $1.00/l inc. at 5%/yrComparison of Net-Benefits and Net-Costs from Various RE-Genset Combinations

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

$10,000,000

$11,000,000

20Gen

/80Hyd

ro B

enefit

20Gen

/80Hyd

ro C

ost

20Gen

/80W

ind Ben

efit

20Gen

/80W

ind Cos

t

20Gen

/80PV B

enefit

20Gen

/80PV C

ost

20Gen

/80SHW

Ben

efit

20Gen

/80SHW

Cos

t

50Gen

/50Hyd

ro B

enefit

50Gen

/50Hyd

ro C

ost

50Gen

/50W

ind Ben

efit

50Gen

/50W

ind Cos

t

50Gen

/50PV B

enefit

50Gen

/50PV C

ost

50Gen

/50SHW

Ben

efit

50Gen

/50SHW

Cos

t

80Gen

/20Hyd

ro B

enefit

80Gen

/20Hyd

ro C

ost

80Gen

/20W

ind Ben

efit

80Gen

/20W

ind Cos

t

80Gen

/20PV B

enefit

80Gen

/20PV C

ost

80Gen

/20SHW

Ben

efit

80Gen

/20SHW

Cos

t

100G

en B

enefi

t

100G

en C

ost


NPV

of B

enef

it / C

ost

RE Benefit

Diesel Benefit

RE Cost

Diesel Cost

39

Starting Price: $1.00/l inc. at 10%/yrComparison of Net-Benefits and Net-Costs from Various RE-Genset Combinations

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

$10,000,000

$11,000,000

$12,000,000

20Gen

/80Hyd

ro B

enefit

20Gen

/80Hyd

ro C

ost

20Gen

/80W

ind Ben

efit

20Gen

/80W

ind Cos

t

20Gen

/80PV B

enefit

20Gen

/80PV C

ost

20Gen

/80SHW

Ben

efit

20Gen

/80SHW

Cos

t

50Gen

/50Hyd

ro B

enefit

50Gen

/50Hyd

ro C

ost

50Gen

/50W

ind Ben

efit

50Gen

/50W

ind Cos

t

50Gen

/50PV B

enefit

50Gen

/50PV C

ost

50Gen

/50SHW

Ben

efit

50Gen

/50SHW

Cos

t

80Gen

/20Hyd

ro B

enefit

80Gen

/20Hyd

ro C

ost

80Gen

/20W

ind Ben

efit

80Gen

/20W

ind Cos

t

80Gen

/20PV B

enefit

80Gen

/20PV C

ost

80Gen

/20SHW

Ben

efit

80Gen

/20SHW

Cos

t

100G

en B

enefi

t

100G

en C

ost


NPV

of B

enef

it / C

ost

RE Benefit

Diesel Benefit

RE Cost

Diesel Cost

40

Return on Investment of D.E. Systems

A comparison of the annual ROI for different Diesel-Renewable D.E. system combinations (hybrids) was compared.

These systems show the influence of increasing the diesel fuel component of the total D.E. mix from 20% to 100% of the capacity requirement for line upgrade deferral each year.

Raising the initial fuel price and accelerating the annual price increase has a significant influence on the optimum diesel-renewable energy mix.

41

ROI / yr for Genset-Hydro DE SystemsInfluence of Hydro on Rising Diesel Prices

-2%

0%

2%

4%

6%

8%

10%

20% 30% 40% 50% 60% 70% 80% 90% 100%

Percentage of Capacity Supplied by Diesel

Ann

ual R

etur

n on

Inve

stm

ent (

RO

I)

Hydro ($1.00@2%/yr)

Hydro ($1.50@2%/yr)

Hydro ($2.00@2%/yr)

Hydro ($1.00@5%/yr)

Hydro ($1.50@5%/yr)

Hydro ($2.00@5%/yr)

Hydro ($1.00@10%/yr)

Hydro ($1.50@10%/yr)

Hydro ($2.00@10%/yr)

Optimum ROI for $1.00 & 2%/yr inc. $1.50 & 2%/yr inc. $1.00 & 5%/yr inc.

Optimum ROI for $2.00 & 2%/yr inc. $1.50 & 5%/yr inc. $2.00 & 5%/yr inc. $1.00 & 10%/yr inc. $1.50 & 10%/yr inc. $2.00 & 10%/yr inc.

42

ROI / yr for Genset-Wind DE SystemsInfluence of Wind on Rising Diesel Prices

-2%

0%

2%

4%

6%

8%

10%

20% 30% 40% 50% 60% 70% 80% 90% 100%


Ann

ual R

etur

n on

Inve

stm

ent (

RO

I)

Wind ($1.00@2%/yr)

Wind ($1.50@2%/yr)

Wind ($2.00@2%/yr)

Wind ($1.00@5%/yr)

Wind ($1.50@5%/yr)

Wind ($2.00@5%/yr)

Wind ($1.00@10%/yr)

Wind ($1.50@10%/yr)

Wind ($2.00@10%/yr)

Optimum ROI for $1.00 & 2%/yr inc. $1.50 & 2%/yr inc. $1.00 & 5%/yr inc.

Optimum ROI for $2.00 & 2%/yr inc. $1.50 & 5%/yr inc. $2.00 & 5%/yr inc. $1.00 & 10%/yr inc. $1.50 & 10%/yr inc. $2.00 & 10%/yr inc.

43

ROI / yr for Genset-PV DE SystemsInfluence of PV on Rising Diesel Prices

-4%

-2%

0%

2%

4%

6%

8%

10%

20% 30% 40% 50% 60% 70% 80% 90% 100%


Ann

ual R

etur

n on

Inve

stm

ent (

RO

I)

PV ($1.00@2%/yr)

PV ($1.50@2%/yr)

PV ($2.00@2%/yr)

PV ($1.00@5%/yr)

PV ($1.50@5%/yr)

PV ($2.00@5%/yr)

PV ($1.00@10%/yr)

PV ($1.50@10%/yr)

PV ($2.00@10%/yr)

Optimum ROI for all scenarios

44

ROI / yr for Genset-PV DE SystemsInfluence of PV on Rising Diesel Prices

-4%

-2%

0%

2%

4%

6%

8%

10%

20% 30% 40% 50% 60% 70% 80% 90% 100%


Ann

ual R

etur

n on

Inve

stm

ent (

RO

I)

PV ($1.00@2%/yr)

PV ($1.50@2%/yr)

PV ($2.00@2%/yr)

PV ($1.00@5%/yr)

PV ($1.50@5%/yr)

PV ($2.00@5%/yr)

PV ($1.00@10%/yr)

PV ($1.50@10%/yr)

PV ($2.00@10%/yr)

Optimum ROI for all scenarios

45

Conclusions

Future fuel price volatility and uncertainty with availability of supply and global warming taxation indicates a preference to at least combine diesel with a renewable component to minimize risk.

Some scenarios, e.g. hydro and wind, indicate best annual ROI includes a 20-80% renewable energy component.

This methodology demonstrates that the accumulated benefits of localized distributed energy (kWh) and capacity (kW) support exceed the costs.

AN investment strategy to replace line capacity upgrades with D.E. also offers a trade-off between direct ROI and intermittent renewable energy.

Net benefits and costs will vary with differing stakeholder / user-operator perspectives.

This analysis shows that for load growth scenarios, distributionnetworks should seriously consider a D.E. investment strategy.

Way Forward

• Identify distribution networks with capacity constraints and increasing customer demand.

• Facilitate collaborative research and development amongst networks with complimentary interests.

• Encourage the Electricity Commission & Transpower to work together with distribution networks to standardize such proceedings and establish industrial best practice.

• Develop a regulatory framework which encourages a decentralised approach to infrastructure development.

Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources

Technology

Transcript of Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources