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
DISTRIBUTION NETWORKDISTRIBUTION NETWORKDISTRIBUTION NETWORK
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
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
Summer 2001-02 1 Nov 01 – 28 Feb 02 1.6 Hours
Summer 2002-03 1 Nov 02 – 28 Feb 03 31.4 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 1996 1 May 96 – 31 Aug 96 52.1 Hours
Winter 1997 1 May 97 – 31 Aug 97 53.8 Hours
Winter 1998 1 May 98 – 31 Aug 98 9.6 Hours
Winter 1999 1 May 99 – 31 Aug 99 34.6 Hours
Winter 2000 1 May 00 – 31 Aug 00 20.0 Hours
Winter 2001 1 May 01 – 31 Aug 01 181.6 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 (MCLM Wind @ 7m/s)
Linear (MCLM Wind @ 5m/s)
Linear (IPP Wind @ 9m/s)
Linear (IPP Wind @ 7m/s)
Linear (IPP Wind @ 5m/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.
23
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.