the economics of grid-connected hybrid distributed generation

THE ECONOMICS OF GRID-CONNECTED HYBRID DISTRIBUTED GENERATION

EEA Annual Conference, June 2003

Dr. Iain Sanders

2

WORK UPDATE

The original paper has been extensively revised and expanded since originally submitted to EEA

The final version of this paper is a 57-page report, entitled: “The Economics of Mini-Scale Embedded Wind-Diesel Generation”

Copies are available by emailing the author at: [email protected]

Other relevant reports may be found at: http://www.designforinnovation.com

3

INTRODUCTION

Introducing distributed energy-based systems: Research motivated by:

Promise of more efficient energy utilisation; and, Opportunity for capturing local renewable energy resources

With minimal use of additional infrastructure. Made possible by:

Local generation solutions relieving distribution network capacity Technology providing alternatives to uneconomic line sections Large numbers of small distributed generators collectively

exporting significant quantities of electricity Matching slow growth in demand with small matching

incremental steps in generation

4

BACKGROUND (PART 1)

A large number of different hybrid Distributed Energy (DE) system sizes and environments have been modelled using IRL’S IDES tools and models.

This study describes a 550kW Westwind-550 Wind Turbine Generator (WTG) and a 550kW Diesel Generator (DG) for deployment within the Orion network region of New Zealand.

The economic assessment uses actual capacity pricing schedules that Orion has developed for its major customers and network-embedded DE operators.

5

BACKGROUND (PART 2)

Financial results were compared for average annual wind speeds of 5, 7 and 9 m/s, using 10-minute average wind data.

A comparison was made between: Releasing capacity from the network (DE operating

as a Major Customer Load Manager (MCLM Operating Scenario); and, Supplying capacity to the network (DE operating

as an Independent Power Producer (IPP Operating Scenario).

6

TWO SCENARIOS COMPARED

WTG-ONLYMCLM

OPERATION

DG-WTG HYBRIDMCLM

OPERATION

DG-ONLYMCLM

OPERATION

DIESELGENSET

DIESELGENSET

A B C

DISTRIBUTION NETWORKDISTRIBUTION NETWORKDISTRIBUTION NETWORK

DIESELGENSET

DIESELGENSET

A B C

DISTRIBUTION NETWORKDISTRIBUTION NETWORK DISTRIBUTION NETWORK

WTG-ONLYIPP

OPERATION

DG-WTG HYBRIDIPP

OPERATION

DG-ONLYIPP

OPERATION

WTG-ONLYMCLM

OPERATION

DG-WTG HYBRIDMCLM

OPERATION

DG-ONLYMCLM

OPERATION

DIESELGENSET

DIESELGENSET

A B C


WTG-ONLYMCLM

OPERATION

DG-WTG HYBRIDMCLM

OPERATION

DG-ONLYMCLM

OPERATION

DIESELGENSET

DIESELGENSET

A B C


DIESELGENSET

DIESELGENSET

A B C

DISTRIBUTION NETWORKDISTRIBUTION NETWORK DISTRIBUTION NETWORK

WTG-ONLYIPP

OPERATION

DG-WTG HYBRIDIPP

OPERATION

DG-ONLYIPP

OPERATION

DIESELGENSET

DIESELGENSET

A B C

DISTRIBUTION NETWORKDISTRIBUTION NETWORK DISTRIBUTION NETWORK DISTRIBUTION NETWORKDISTRIBUTION NETWORK DISTRIBUTION NETWORK

WTG-ONLYIPP

OPERATION

DG-WTG HYBRIDIPP

OPERATION

DG-ONLYIPP

OPERATION

MCLM Operating Scenario

IPP Operating Scenario

7

SCENARIO PAYMENT OPTIONS Customer Status Scenario Payment Options (Typical)

(GCLM) Load Line Rental Fee

Management Single / Multiple Energy Tariff(s)(may / may not be time-related)

General Customer (GC)

Connection Fee (IPP)

Generation Peak Period Demand Pricing

TOU Energy Pricing or Net-metering Connection Fee (MCLM) Load

Management Assessed Capacity (AC) Pricing

Control Period Demand (CPD) Pricing

Major Customer (MC)

TOU Energy Pricing

(IPP) Connection Fee

Generation Peak Period Demand (PPD) Pricing

TOU Energy Pricing

8

ENERGY PAYMENT OPTIONSPRICE SCHEDULE - Variable volume for 3 Years

Area: ChristchurchCustomer: Industrial Research Ltd

Month 0000-0330 0400-0730 0800-1130 1200-1530 1600-1930 2000-2330 0000-0330 0400-0730 0800-1130 1200-1530 1600-1930 2000-2330Mar-03 3.55 4.51 6.72 6.10 5.79 5.06 3.92 3.40 4.78 4.30 4.25 4.14Apr-03 3.56 4.51 6.73 6.10 5.79 5.06 3.92 3.41 4.79 4.30 4.25 4.14

May-03 4.62 5.37 7.10 6.11 7.59 6.21 4.86 3.48 4.98 4.42 6.25 4.86Jun-03 5.16 6.00 7.93 6.83 8.48 6.93 5.42 3.89 5.56 4.94 6.98 5.43Jul-03 5.00 5.81 7.67 6.61 8.21 6.71 5.25 3.76 5.38 4.78 6.76 5.26

Aug-03 4.91 5.71 7.54 6.50 8.07 6.60 5.16 3.70 5.29 4.70 6.64 5.17Sep-03 4.22 4.91 6.49 5.59 6.94 5.68 4.44 3.18 4.55 4.04 5.72 4.45Oct-03 3.45 4.38 6.53 5.92 5.62 4.92 3.81 3.31 4.65 4.18 4.13 4.02Nov-03 2.75 3.49 5.21 4.72 4.48 3.92 3.03 2.64 3.70 3.33 3.29 3.21Dec-03 2.50 3.17 4.72 4.28 4.07 3.56 2.75 2.39 3.36 3.02 2.98 2.91Jan-04 2.67 3.38 5.04 4.57 4.34 3.80 2.94 2.55 3.59 3.22 3.18 3.11Feb-04 3.12 3.95 5.90 5.34 5.07 4.44 3.44 2.99 4.19 3.77 3.72 3.63Mar-04 3.96 5.02 7.48 6.78 6.44 5.63 4.36 3.79 5.32 4.78 4.73 4.61Apr-04 3.96 5.02 7.49 6.79 6.44 5.64 4.36 3.79 5.33 4.79 4.73 4.61

May-04 5.14 5.98 7.90 6.80 8.45 6.91 5.40 3.87 5.54 4.92 6.95 5.41Jun-04 5.74 6.68 8.82 7.60 9.44 7.71 6.04 4.32 6.19 5.50 7.77 6.05Jul-04 5.56 6.46 8.54 7.35 9.13 7.47 5.84 4.19 5.99 5.32 7.52 5.85

Aug-04 5.46 6.35 8.39 7.23 8.98 7.34 5.74 4.11 5.89 5.23 7.39 5.75Sep-04 4.70 5.47 7.22 6.22 7.73 6.32 4.94 3.54 5.07 4.50 6.36 4.95Oct-04 3.84 4.87 7.27 6.59 6.26 5.47 4.24 3.68 5.17 4.65 4.59 4.48Nov-04 3.06 3.89 5.79 5.25 4.99 4.36 3.38 2.93 4.12 3.70 3.66 3.57Dec-04 2.78 3.52 5.26 4.76 4.52 3.96 3.06 2.66 3.74 3.36 3.32 3.24Jan-05 2.97 3.76 5.61 5.09 4.83 4.22 3.27 2.84 3.99 3.59 3.54 3.46Feb-05 3.47 4.40 6.56 5.95 5.65 4.94 3.82 3.32 4.67 4.19 4.14 4.04Mar-05 4.22 5.36 7.99 7.25 6.88 6.02 4.66 4.05 5.69 5.11 5.05 4.92Apr-05 4.23 5.36 8.00 7.25 6.88 6.02 4.66 4.05 5.69 5.11 5.05 4.92

May-05 5.49 6.39 8.43 7.27 9.02 7.38 5.77 4.14 5.92 5.26 7.43 5.78Jun-05 6.13 7.13 9.42 8.12 10.08 8.24 6.45 4.62 6.61 5.87 8.30 6.46Jul-05 5.94 6.90 9.12 7.86 9.76 7.98 6.24 4.47 6.40 5.68 8.03 6.25

Aug-05 5.84 6.79 8.96 7.72 9.59 7.84 6.13 4.39 6.29 5.59 7.89 6.14Sep-05 5.02 5.84 7.71 6.64 8.25 6.75 5.28 3.78 5.41 4.81 6.79 5.29Oct-05 4.10 5.21 7.76 7.04 6.68 5.84 4.52 3.93 5.52 4.96 4.90 4.78Nov-05 3.27 4.15 6.19 5.61 5.33 4.66 3.61 3.13 4.40 3.96 3.91 3.81Dec-05 2.97 3.77 5.61 5.09 4.83 4.23 3.27 2.84 3.99 3.59 3.55 3.46Jan-06 3.17 4.02 5.99 5.43 5.16 4.51 3.49 3.04 4.26 3.83 3.79 3.69Feb-06 3.70 4.70 7.01 6.35 6.03 5.28 4.08 3.55 4.99 4.48 4.43 4.32

4.17 5.06 7.11 6.30 6.83 5.77 4.49 3.55 5.03 4.49 5.33 4.62

5.87 Business Day 4.58 Non-Business Day

251 Days 5.471 Overall Average 114 Days

Business Day Non-Business day

9

CAPACITY SAVING SCHEDULECPD Date Start Time End Time CPD Duration11 Feb 2003 11:00 11:17 17 mins07 J an 2003 20:03 01:46 343 mins07 J an 2003 18:09 19:36 87 mins06 J an 2003 17:56 00:49 413 mins05 J an 2003 00:22 00:57 35 mins04 J an 2003 23:24 23:39 15 mins03 J an 2003 23:23 01:07 104 mins03 J an 2003 22:03 22:49 46 mins03 J an 2003 18:04 19:33 89 mins03 J an 2003 00:23 01:09 46 mins02 J an 2003 23:26 23:44 18 mins01 J an 2003 00:26 01:09 43 mins30 Dec 2002 23:29 23:52 23 mins26 Nov 2002 00:42 00:42 0 mins07 Nov 2002 17:50 21:14 204 mins06 Nov 2002 23:20 01:23 123 mins06 Nov 2002 17:57 22:51 294 mins

MCLM: Chargeable Major Customer Summer Periods

Season Control Period Total Duration

Summer 2000-01 1 Nov 00 – 28 Feb 01 81.1 Hours



Season Control Period Total DurationWinter 1994 1 May 94 – 31 Aug 94 61.1 Hours

Winter 1995 1 May 95 – 31 Aug 95 80.9 Hours







Winter 2002 1 May 02 – 31 Aug 02 111 Hours

MCLM: Chargeable Major Customer Winter Periods

10

CAPACITY GENERATION SCHEDULEDate Half Hour Ending Duration Cumulative

Thu, 27-3-2003 19:30, 20:00, 20:30, 21:00, 21:30, 22:00 3.0 108.5 Wed, 26-03-2003 19:30, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30 3.5 105.5 Tue, 25-03-2003 19:00, 19:30, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30, 23:00 4.5 102.0 Mon, 24-03-2003 19:30, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30, 23:00, 24:00 4.5 97.5

Fri, 21-03-2003 20:00, 20:30, 21:00, 21:30 2.0 93.0 Thu, 20-03-2003 19:30, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30 3.5 91.0

Wed, 19-03-2003 20:00, 20:30, 21:00, 21:30, 22:00, 22:30 3.0 87.5 Tue, 18-03-2003 20:00, 20:30, 21:00, 21:30, 22:00, 22:30, 23:00 3.5 84.5 Mon, 17-03-2003 18:30, 19:00, 19:30, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30, 23:00 5.0 81.0

Fri, 14-03-2003 01:00 0.5 76.0 Thu, 13-03-2003 21:30, 22:00, 22:30, 23:00 2.0 75.5

Wed, 12-03-2003 01:00, 01:30 1.0 73.5 Tue, 11-03-2003 01:00, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30, 23:00, 24:00 4.5 72.5 Mon, 10-03-2003 18:00, 18:30, 19:00, 19:30, 21:00, 21:30, 22:00, 22:30, 23:00, 24:00 5.0 68.0

Fri, 7-03-2003 01:00 0.5 63.0 Thu, 6-03-2003 17:00, 17:30, 18:00, 18:30, 19:00, 21:30, 22:00, 22:30 4.0 62.5

Thu, 13-02-2003 22:30 0.5 58.5 Mon, 10-02-2003 17:30, 18:00, 18:30, 22:30 2.0 58.0 Wed, 8-01-2003 00:30, 01:00, 01:30, 02:00, 02:30 2.5 56.0 Tue, 7-01-2003 00:30, 01:00, 01:30, 18:30, 19:00, 19:30, 20:00, 20:30, 21:00,

21:30, 22:00, 22:30, 23:00, 23:30, 24:00 7.5 53.5

Mon, 6-01-2003 18:00, 18:30, 19:00, 19:30, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30, 23:00, 23:30, 24:00

6.5 46.0

Sat, 4-01-2003 00:30 0.5 39.5 Fri, 3-01-2003 01:00, 01:30, 17:30, 18:00, 18:30, 19:00, 19:30, 20:00, 20:30,

22:30, 23:00, 23:30, 24:00 6.5 39.0

Thu, 2-01-2003 22:30, 23:00, 24:00 1.5 32.5 Wed, 1-01-2003 00:30, 01:00, 01:30 1.5 31.0 Tue, 31-12-2002 00:30, 01:00, 17:00, 17:30, 18:30, 19:00, 24:00 3.5 29.5 Mon, 30-12-2002 19:00, 22:30, 23:00, 24:00 2.0 26.0

Fri, 27-12-2002 24:00 0.5 24.0 Tue, 24-12-2002 01:00, 24:00 1.0 23.5 Mon, 11-11-2002 18:30, 19:00, 19:30, 20:00, 20:30 2.5 22.5

Thu, 7-11-2002 00:30, 01:00, 01:30, 02:00, 18:00, 18:30, 19:00, 19:30, 20:00, 20:30, 21:00, 21:30, 22:00

6.5 20.0

Wed, 6-11-2002 15:30, 16:00, 16:30, 18:30, 19:00, 19:30, 20:00, 20:30, 21:00, 21:30, 22:00, 22:30, 23:00, 23:30, 24:00

7.5 13.5

Tue, 5-11-2002 17:30, 22:00 1.0 6.0 Mon, 4-11-2002 22:00, 22:30 1.0 5.0

Wed, 23-10-2002 16:30, 17:00 1.0 4.0 Tue, 22-10-2002 17:30, 18:00, 18:30, 19:00, 19:30, 20:00 3.0 3.0

IPP: Summer Chargeable Peaks for Capacity Generation

Season Peak Period Total Duration

Summer 2000-01 1 Oct 00 – 31 Mar 01 307.5 Hours

Summer 2001-02 1 Oct 01 – 31 Mar 02 53 Hours

Summer 2002-03 1 Oct 02 – 31 Mar 03 108.5 Hours

IPP: Winter Chargeable Peaks for Capacity Generation

Season Peak Period Total Duration

Winter 2001 1 Apr 01 – 30 Sep 01 318.5 Hours

Winter 2002 1 Apr 02 – 30 Sep 02 233 Hours

11

CAPACITY PRICING SCHEDULE

Pricing Definition Line Transmission Delivery

Fixed (Connection) - $500.05 ----- - $500.05/year

Control Period Demand - $60.00 - $21.92 - $81.92/kVA/year

Assessed Capacity - $24.40 - $22.00 - $46.40/kVA/year

Pricing Definition Line Transmission Delivery

Fixed (Connection): GC - $0.00 ----- - $0.00/year

Fixed (Connection): MC - $500.05 ----- - $500.05/year

Peak Period Demand $66.70 $33.30 $100.00/kVA/year

CAPACITY SAVING SCENARIO

CAPACITY GENERATION SCENARIO

12

Diesel costs are based on data supplied by Transmissions & Diesels Ltd, giving the following cost algorithms:

Capital Cost = $2,042.20(kW Capacity)-0.3552 / kW Maintenance Cost = $1,333.30 + $6.67(kW Capacity) / year Operating periods for the diesel generator broken up into

continuous 10-minute periods, for matching diesel energy production with the corresponding PPD.

Cost of diesel prior to conversion = $0.7030 / Litre Annual fuel price increase = 2% Maximum diesel conversion efficiency = 37% (for a 550kW

generator) Diesel conversion efficiency varies with its operating capacity (20-

100% of max.) Diesel plant operating life = 40,000 hours before replacement

required Wind turbine cost (including O&M) = $2,725 / kW

MAJOR MODELLING ASSUMPTIONS

13

Annual CPI (inflation for O&M) increase = 3% Project life = 20 years Electricity purchase price (from the energy retailer) = 5.47cents/kWh Electricity sales price (to the energy retailer) = 4.92cents/kWh Annual energy price increase (buying and selling) = 1% Discount rate = 5% Cost of finance = 0% or 10% paid monthly over 20 year fixed term Annual wind speeds investigated for the 550kW wind turbine = 5, 7,

and 9m/s Scenarios run for 2000-01, 2001-02, and 2002-03 summer PPD

seasons Cost of metering systems required to implement the scenarios

shown, excluded Results do not consider tax deductions on loan repayments or on

the net annual gains made from running profitable operations.

MAJOR MODELLING ASSUMPTIONS

14

PROJECT FINANCIAL ANALYSISENERGY Firm kW Firm kWh / yr WTG Total kWh/yr WTG kWh/yr Export Diesel kWh/yr ExportPRODUCTION 550 59,675 1,683,956.70 1,683,956.70 83,121.04INCOME OR Retail Firm $ / kWh Buyback $ / kWh Savings / kVA / Yr Retail Savings / Yr Export Income / Yr Capacity Savings / YrSAVINGS / YR $0.0547 $0.0492 $81.92 $0.00 $86,993.24 $65,499.95ANNUAL WTG O&M / Year Diesel O&M / Year Fuel Cost / Year WTG O&M / Month (Eq.) Diesel O&M / Mth (Eq.) Fuel Cost / MthO&M COSTS $20,207 $5,000 $5,569.11 $1,684 $417 $464.09TOTAL CAPITAL WTG Price WTG Freight Cost WTG Install Cost Diesel Cost / kW No. of Units Diesel Size Diesel CostBORROWED $320,000 $20,000 $124,826 $217 1 550 $119,422

FIRM CAPACITY REQUIREMENT 550 Fuel Inc. / yr 2% Revenue or Cost in $ / kWh $0.058Principal $584,247.94 Fuel Cost / litre Inflation / yr 3% NPV $1,274,073.91Term (yrs) 20 $0.7030 Discount % 5% 550 kW FIRM IRR 16.40%Days / pay 31 MJ/m3 (net) Breakdown IDES COMBINATION Payback (yrs) 5.89Annual % 0.00000% 37,794 Borrowings WW-550 + Gensets ROI (average) 17.65%Daily % 0.00000% $/GJ WTG Purchase $320,000.00 WTG: $2,725/kW @ 7 M/S/YRMonthly Repay $2,012.41 $18.60 WTG Freight $20,000.00 SUMMER DEMAND CONTROL PERIODS - 2002/03$/kWh O&M $0.012 Fuel ($ / kWh) WTG Install $124,826.00Grid Inc./yr 1% $0.0670 Diesel Capital $119,421.94 NPV

Year Annual Income Annual O&M Annual Fuel Annual Payments Total Annual Cost PW Factor Disc. Cost Firm kWh Prod. Disc. Prod.1 $152,493.19 -$25,207.47 -$5,569.11 -$24,148.91 $97,567.70 0.952 $92,921.62 1,767,123.66 1,682,974.912 $154,018.12 -$25,963.69 -$5,680.49 -$24,148.91 $98,225.02 0.907 $89,092.99 1,767,123.66 1,602,833.253 $155,558.30 -$26,742.60 -$5,794.10 -$24,148.91 $98,872.68 0.864 $85,409.94 1,767,123.66 1,526,507.864 $157,113.88 -$27,544.88 -$5,909.98 -$24,148.91 $99,510.11 0.823 $81,867.21 1,767,123.66 1,453,817.015 $158,685.02 -$28,371.22 -$6,028.18 -$24,148.91 $100,136.70 0.784 $78,459.72 1,767,123.66 1,384,587.636 $160,271.87 -$29,222.36 -$6,148.75 -$24,148.91 $100,751.85 0.746 $75,182.58 1,767,123.66 1,318,654.887 $161,874.59 -$30,099.03 -$6,271.72 -$24,148.91 $101,354.92 0.711 $72,031.05 1,767,123.66 1,255,861.798 $163,493.34 -$31,002.00 -$6,397.16 -$24,148.91 $101,945.26 0.677 $69,000.57 1,767,123.66 1,196,058.859 $165,128.27 -$31,932.06 -$6,525.10 -$24,148.91 $102,522.19 0.645 $66,086.72 1,767,123.66 1,139,103.67

10 $166,779.55 -$32,890.02 -$6,655.60 -$24,148.91 $103,085.01 0.614 $63,285.25 1,767,123.66 1,084,860.6411 $168,447.35 -$33,876.73 -$6,788.71 -$24,148.91 $103,632.99 0.585 $60,592.07 1,767,123.66 1,033,200.6112 $170,131.82 -$34,893.03 -$6,924.49 -$24,148.91 $104,165.39 0.557 $58,003.19 1,767,123.66 984,000.5813 $171,833.14 -$35,939.82 -$7,062.98 -$24,148.91 $104,681.43 0.530 $55,514.80 1,767,123.66 937,143.4114 $173,551.47 -$37,018.01 -$7,204.24 -$24,148.91 $105,180.31 0.505 $53,123.20 1,767,123.66 892,517.5315 $175,286.99 -$38,128.55 -$7,348.32 -$24,148.91 $105,661.20 0.481 $50,824.84 1,767,123.66 850,016.7016 $177,039.86 -$39,272.41 -$7,495.29 -$24,148.91 $106,123.24 0.458 $48,616.28 1,767,123.66 809,539.7117 $178,810.26 -$40,450.58 -$7,645.19 -$24,148.91 $106,565.56 0.436 $46,494.20 1,767,123.66 770,990.2018 $180,598.36 -$41,664.10 -$7,798.10 -$24,148.91 $106,987.24 0.416 $44,455.41 1,767,123.66 734,276.3819 $182,404.34 -$42,914.02 -$7,954.06 -$24,148.91 $107,387.34 0.396 $42,496.82 1,767,123.66 699,310.8420 $184,228.38 -$44,201.44 -$8,113.14 -$24,148.91 $107,764.88 0.377 $40,615.45 1,767,123.66 666,010.3221 $0.00 $0.00 $0.00 $0.00 $0.00 0.359 $0.00 0.00 0.0022 $0.00 $0.00 $0.00 $0.00 $0.00 0.342 $0.00 0.00 0.0023 $0.00 $0.00 $0.00 $0.00 $0.00 0.326 $0.00 0.00 0.0024 $0.00 $0.00 $0.00 $0.00 $0.00 0.310 $0.00 0.00 0.0025 $0.00 $0.00 $0.00 $0.00 $0.00 0.295 $0.00 0.00 0.00

Total $3,357,748.10 -$677,334.04 -$135,314.73 -$482,978.30 $2,062,121.04 $1,274,073.91 22,022,266.76

YEARLY SAVINGS AND NET ACCUMULATED SAVINGS

-$1,000,000

-$500,000

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

YEAR

DOLL

ARS

Annual SavingsInvestment Balance

15

MCLM ENERGY & CAPACITY SAVINGSComparison of MCLM Energy and Capacity Savings for the Summer 2002-03 CPD

Season

$0$20,000$40,000$60,000$80,000

$100,000$120,000$140,000$160,000$180,000$200,000

WTG-Only @5m/s

WTG-Only @7m/s

WTG-Only @9m/s

DG-WTGHybrid @

5m/s

DG-WTGHybrid @

7m/s

DG-WTGHybrid @

9m/s

DG-Only

Distributed Generation Option

Ann

ual S

avin

gs

AC & CP D Savings from Capacity / yr

Savings from Energy / yr

16

IPP ENERGY & CAPACITY REVENUESComparison of IPP Energy and Capacity Revenues for the Summer 2002-03 PPD

Season

$0$20,000$40,000$60,000$80,000

$100,000$120,000$140,000$160,000$180,000

WTG-Only@ 5m/s

WTG-Only@ 7m/s

WTG-Only@ 9m/s

DG-WTGHybrid @

5m/s

DG-WTGHybrid @

7m/s

DG-WTGHybrid @

9m/s

DG-Only

Distributed Generation Option

Ann

ual S

avin

gs

P P D Revenue from Capacity / yr

Revenue from Energy / yr

17

COMPARING MCLM & IPP SCENARIOSIRR Based on Seasonal Control (MCLM / Load Mgt) or Peak (IPP / Generator) Period

Duration, w ith 10% Interest on Finance with WTG Priced at $2,725/kW over Life

-5%

0%

5%

10%

15%

20%

25%

30%

0 200 400 600 800 1000Seasonal Peak / Control Demand Period Duration

Inte

rnal

Rat

e of

Ret

urn

(IRR

)

DG-Only (Generator)

DG-Only (Load Mgt)

DG & WTG @ 7m/s(Generator)DG & WTG @ 7m/s(Load Mgt)WTG-Only @ 7m/s(Generator)WTG-Only @ 7m/s(Load Mgt)P oly. (DG-Only(Generator))Linear (DG-Only(Load Mgt))Linear (WTG-Only @7m/s (Load Mgt))

18

WIND ENERGY CONTRIBUTIONS

Percentage WInd Energy (kWh) Contribution Under Different Annual Wind Speed Regimes and MCLM and IPP Operating Scenarios

60%

65%

70%

75%

80%

85%

90%

95%

100%

0 50 100 150 200 250 300 350 400 450

CPD / PPD Duration (Hours / Season = Hours / Year)

Perc

enta

ge E

nerg

y Co

ntrib

utio

n fro

m W

ind

MCLM Wind @ 5m/s

MCLM Wind @ 7m/s

MCLM Wind @ 9m/s

IPP Wind @ 5m/s

IPP Wind @ 7m/s

IPP Wind @ 9m/s

Linear (MCLM Wind @ 9m/s)



Linear (IPP Wind @ 9m/s)



19

WIND VS. WIND-DIESEL HYBRIDComparison of Wind-Only and DG-Wind Hybrid Results for the MCLM and IPP

Operating Scenarios, Using CPD and PPD Data for Summer 2002-03

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

5 7 9

Average Annual Wind Speed (m/s)

Inte

rnal

Rat

e of

Ret

urn

(IRR

) with

0%

Inte

rest

on

Fina

nce

Wind-Only MCLMWind-Only IPPDG-Wind Hybrid MCLMDG-Wind Hybrid IPP

20

INFLUENCE OF GOVT. INCENTIVES Influence of Renewable Energy Incentives on the Financial Viability of DG-WTG

Hybrid Investments (Lifecycle cost = $2.725/kW) w ith 0% Financing

0%

5%

10%

15%

20%

25%

30%

35%

40%

0 100 200 300 400 500 600 700

Operating Period (Hours)

Inte

rnal

Rat

e of

Ret

urn

(IRR

)

DG-Only BasecaseDG-Only -1c/kWh Carbon TaxDG-Only -2c/kWh Carbon TaxBDG-WTG Hybrid BasecaseBDG-WTG Hybrid +1c/kWh IncentiveBDG-WTG Hybrid +2c/kWh Incentive

21

AVERAGE PPD WHOLESALE PRICESRelationship Between PPD Schedule and Corresponding Benmore GXP

Average Electricity Wholesale Price

0

5

10

15

20

25

0 20 40 60 80 100 120

Cumulative PPD Hours For Summer 2002-03

Ave

rage

Who

lesa

le E

lect

ricity

Pric

e C

orre

spon

ding

to P

PD e

ach

Mon

th

NOV 02

JAN 03

MAR 03

OCT 02FEB

03DEC 02

22

OPTIONS FOR IMPROVEMENT

Maximize the diesel output during the CPD and PPD, to increase the average capacity delivered.

Optimize the blend of load management (MCLM scenario) with grid-injected generation (IPP scenario) to maximize savings / revenue.

Consider load-following as an alternative option to constant capacity-support for the MCLM scenario, provided the supply exceeds the necessary demand.

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SUMMARY OF RESULTS

Based on the operating scenarios used in this study, one hundred 550kW DG-WTG Hybrid systems could deliver:

168 GWh/year from wind energy with an average wind speed of 7m/s; and,

11 GWh/year from diesel fuel – when supplying capacity for an average of 200hours/year.

This represents an average generation of 20MW, and a peak capacity delivered when required of 55MW.

The diesel gensets could alternatively be run on biodiesel – the potential exists for biodiesel to compete on price with ordinary diesel at the pump.

24

CONCLUSIONS I

Our research has focused on the provision of capacity support to the network from embedded generation, at sizes down to the smallest level.

All embedded generators should be able to obtain a price for exported energy that at least reflects the pricing structure imposed on them by the supply industry for the purchase of energy –minus a regulated administration charge.

This arrangement is not currently available to general customers as of right.

25

CONCLUSIONS II

This study demonstrates the impact that a fair payment for delivery of firm capacity can have on the economics of embedded generation.

There is no reason why similar or even better capacity support cannot be delivered from sufficient micro-scale household generation and / or mini-scale commercial level generators to produce the same accumulated (amalgamated) capacity.

There should be no barrier to any customer (including general customers) getting a return from network support.

26

CONCLUSIONS III

It is apparent that there are many mini- and small-scale renewable generation projects that are close to viability.

These projects could make a positive contribution, in conjunction with traditional energy infrastructure, towards alleviating looming energy supply problems.

Overseas, such desirable emerging technologies are usually given “kick-start” incentives to allow the market to become self-sustaining.

These pragmatic approaches to developing a new industry are not yet taken seriously in New Zealand.