Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasScenarios for Distributed Energy In...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areas   electricity from otherwise uneco...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areas    4. Reduce risk of failure of ov...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasconditions and costs, because of th...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasresources for long-term sustainable...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasRuatoria Feeder Case StudyThe Ruato...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasillustrate the potential impact of ...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasAssessing Costs of Network Upgrades...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasthe five DE scenarios mentioned pre...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasriver. If for example, the river ca...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasprofile in figure 12.The solar hot ...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areas                            • grid-...
Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasIt has been observed that method 1:...
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources
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Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources

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This project examined the economic viability of using distributed renewable resources to defer costly electricity distribution network upgrades in rural areas using information provided by three independent electricity distribution networks.

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Line Upgrade Deferral Scenarios for Distributed Renewable Energy Resources

  1. 1. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasScenarios for Distributed Energy Investment as an Alternative toDistribution Line Upgrades in Rural AreasBy Iain Sanders, Sustainable Innovative Solutions Limited, and Alister Gardiner, IndustrialResearch LimitedAbstractIn this paper, we identify and evaluate various ‘best-case scenarios’ for investing in decentralisedmicro-generation from a utility-driven, distribution network perspective. A distribution line experiencingsignificant over-capacity from increasing customer demand is used to determine the Net PresentValue (NPV) of five different modular, distributed energy systems: (1) hydroelectric power (HEP) withdiesel genset (DGN) support; (2) wind turbine generation (WTG) with DGN support; (3) photovoltaics(PVS) with DGN support; (4) solar hot water (SHW) with DGN support; and (5) DGN by itself, as areference case.The study considers the value of distributed energy (DE) in deferring or eliminating distribution lineenergy- / capacity-based upgrades. The basic principle applied in this study is that the distributedgeneration installed consists of a combination of fuel-based (DGN) generation and intermittentrenewable energy (RE) to ensure that “normal” supply reliability can be delivered at all times,irrespective of RE availability. Typical RE supply profiles are used to indicate the likely mix of RE andDGN supply throughout the year on a continuous half-hourly basis. The scale and format of theparticular technologies is not specified, instead these are simply identified as opportunity costs.As a typical case study involving real “industry” data, the NPV of DE as a line upgrade deferral optionwas compared with a “business as usual” scenario for a rural distribution line in the Eastland NetworksLimited (ENL) region of the north island of New Zealand. For the data presented in this report, theannual energy demand growth rate was exaggerated and extended over a 20-year timeframe toemphasize the potential contribution that DE could have on the energy / capacity supply mix forregions of high growth. The net results were almost always in favour of DE line upgrade deferral (asopposed to a “business as usual” network management arrangement) under the conditions assumedfor this study. No attempt was made to account for any contributions of heat generated by the fuelbased (diesel assumed) generation. Combined Heat and Power (CHP) would add substantial value byproviding additional end use energy from the fuel resource.IntroductionOver the last nine years, Industrial Research has evaluated a wide range of resource opportunities foradopting Renewable Distributed Energy (RDE) technologies in New Zealand. The objective has beento evaluate and demonstrate the techno-economic viability of micro- (less than 100kW capacity), mini-(between 100kW and 1000kW capacity) and small-scale (between 1MW and 10MW capacity) RDEsystems in New Zealand. In the process specialised tools and methodologies have been developed tofulfil this purpose. (Unless ‘scale’ is specifically mentioned, the term ‘small’ will refer to anything frommicro-scale to small-scale inclusive).This research into distributed energy-based systems has been motivated by the promise of moreefficient energy utilisation and the opportunity for capturing local renewable energy resources withminimal use of additional infrastructure. Specific network benefits are possible through:1. Local generation solutions relieving distribution network capacity while maintaining utilisation (fig.1).2. Technology that will provide alternatives to uneconomic network sections.3. Creating the means for large numbers of small distributed generators to export aggregatedDr. Iain Sanders Sustainable Innovative Solutions Limited Page 1 of 25
  2. 2. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areas electricity from otherwise uneconomic network assets to different network users (see figure 2).4. Ability to track slow growth in demand with small matching incremental steps in generation, thus avoiding or delaying major upgrades. 2 0 0 3 L o a d D u r a t io n C u r v e fo r L y n d o n L in e 100 90 80 8 0 k W M A X IM U M S T A N D A R D O P E R A T IN G C A P A C IT Y T H R E S H O L D 70 Firm DE 6 0 k W B A S E - C A S E U S E D F O R L O A D D U R A T IO N P R O J E C T IO N S Capacity (kW) 60 50 40 30 Primary objective for DE to 20 meet peak load requirements 10 0 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 227 454 680 907 1 C u m m u la t iv e H o u r s o f t h e Y e a r MainPower Lyndon (ML) line Predicted Load Duration Curve Typical Example What is Line Upgrade Deferral?Figure 1: Local generation solutions to relieve peak distribution network capacity T o d a y s T o m o r r o w s C e n tr a l U tility D is tr ib u te d U tility ? C e n tr a l G e n e r a tio n C e n tr a l G e n e r a t io n W in d R em o te G en set L oads PV F u e l C e ll B a tte r y C u sto m er C u sto m ers E f f ic ie n c y M ic r o tu r b in e 1 Can Costly Upgrades Be Prevented? © 2 0 0 2 D i s t r i b u te d U t il it y A s s o c i a t e sFigure 2: Redesigning Distribution Networks Around Locally Available Distributed Energy ResourcesLocal distributed energy provides significant benefits to various stakeholders: 1. Support adoption of environmentally friendly energy supply alternatives; 2. Provide supplementary revenue for farmers – other network customers; 3. Reduce burden of long-term infrastructure upgrades on network customers;Dr. Iain Sanders Sustainable Innovative Solutions Limited Page 2 of 25
  3. 3. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areas 4. Reduce risk of failure of overloaded transmission and distribution lines, and potentially increase system security; 5. Promote supply energy-efficiency; 6. Only invest in what is required using modular distributed energy (DE) technologies; and, 7. Potentially provide additional revenue / savings for network operators.Using integrated distributed energy technologies, some technologies may be owned and controlled bythe networks, and some technologies may be owned and controlled by the customers. These potentialnetwork benefits contrast with the more popular view that distributed generation threatens thetraditional electricity supply infrastructure by taking away energy delivery but not alleviating capacitydemands. Note that the network benefits are case specific, and are primarily based on demand growthscenarios. Previous work by Industrial Research has identified few if any benefits accruing todistribution networks from distributed generation in regions with static or declining load.In the main, small-scale technology developers have been preoccupied with reducing the costs of theirown particular product in the high volume micro- / mini-scale embedded generation marketplace.Unfortunately, no single technology can yet provide the quality of service delivered by the distributionnetwork, at the distribution network price. For example, a wind generator cannot guarantee firmcapacity, so the network must provide this; and, while a diesel genset can deliver capacity the cost ofenergy from a diesel genset is generally too high, so it is relegated to a standby function. This paperevaluates the ability of combinations of local resources to deliver matching energy and firm capacity tocomplement grid based electricity services, and the value accrued from offsetting investment costsassociated with local growth.Background of ResearchIndustrial Research Limited (IRL) has worked with Eastland Networks Limited (ENL) support toevaluate the potential economic impact of Distributed Energy Resources (DERs) on the East Coastpotion of their distribution network (see figure 3). This was chosen as typical of rural network asset Eastland Network TE ARAROA INPORT RUATORIA INPORT Te Puia is fed from Tokomaru Bay 50/11kV line TOKOMARU BAY INPORT FOCUS TOLAGA BAY INPORT Main Case Study – a section of the Eastland Network was chosen – The Ruatoria 11kV Feeder from the GISBORNE Ruatoria 50/11kV INPORT SubstationFigure 3: East Coast Portion of Eastland Networks LimitedDr. Iain Sanders Sustainable Innovative Solutions Limited Page 3 of 25
  4. 4. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasconditions and costs, because of the limited availability of detailed asset valuation. The East Coastportion of the Eastland Network stretches from Gisborne in the south to Hick’s Bay in the north. Asingle 50kV subtransmission line carries electricity from Gisborne up the coast to four substations at: 1.Tolaga Bay, 2. Tokomaru Bay, 3. Ruatoria, and 4. Te Araroa (see figure 3).These four substations deliver power to the communities on the East Coast via 14 11kV feeders (seefigure 4). The 11kV feeders distribute electricity to the communities and individuals in the region. TOLAGA B AY TOKOMARU BAY RUATORIA TE ARAROA SUBSTATION SUBSTATION SUBSTATION SUBSTATION FROM 4 TH SUBSTATION: FEEDERS L, M & N FROM 3 RD SUBSTATION: FEEDERS H, I, J & K FROM 2 ND SUBSTATION: FEEDERS E, F & G FROM 1 ST SUBSTATION: FEEDERS A, B, C & DFigure 4: Eastland Network’s East Coast feeders and substationsMotivation for the ResearchIt is getting harder for electricity distribution networks to cover their O&M and replacement costs oninfrastructure for the following reasons: 1. Increasing or remote rural population hot spots putting pressure (often seasonal) on existing rural networks (although this reason is not particularly relevant to the East Coast region); 2. Most rural network infrastructure is old, nearing the end of its normal life, making O&M costly and in need of replacement; and, 3. Routine preventive O&M is less affordable, resulting in more severe and costly failures when they happen.New Zealand is rich in alternative energy resources which could make a substantial contributiontowards meeting the country’s future energy demand through DE grid-support projects. At presenthowever, these generation technologies are hard to justify on a purely user “demand side” basis. Iftreated as a “supply side” asset, (as they potentially are via the right to connect) the economic casecan improve dramatically. There is substantial potential for DE technologies to reduce peak demandand hence extend the life of New Zealand’s ageing network infrastructure. These opportunities may beextended in the future to automatic islanding and self-healing interactive micro-grids delivering higherreliability at lower service costs. Furthermore, local communities are keen to develop naturalDr. Iain Sanders Sustainable Innovative Solutions Limited Page 4 of 25
  5. 5. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasresources for long-term sustainable development or as part of locally-sponsored sustainabilityinitiatives and programs. Providing that the regulatory and market environment is adapted to recognizethe benefits, these technologies will transform many aspects of network power in the future.Methodology of the StudyIn this study, three load growth scenarios representing a 1.5%, 5% and 10% increase in peak load peryear for 20 years were selected and used to demonstrate the potential value from deferringinfrastructure line upgrades, by using supplementary distributed energy to provide the peak loadshortfall whenever the physical limit of the distribution line was exceeded. The peak load shortfall wascalculated both as a capacity shortfall (in kW) and an energy shortfall requirement (in kWh), so thatthe line upgrade deferral value (of investment in network infrastructure capacity to meet the peak loadshortfall) could be measured as a Net Present Value (NPV) marginal distribution capacity cost(MDCC) in $/kW/year (known as the capacity-valuation method), and as a NPV marginal distributionenergy cost (MDEC) in $/kWh (known as the energy-valuation method).The peak load capacity / energy shortfall requirement was determined by selecting an appropriatecapacity threshold (i.e. physical upper limit of feeder capacity supply) for the distribution feedermeeting the demand. In this report, we cover the 10% annual load growth scenario, and show howdistributed energy can be used to reliably meet the capacity / energy shortfall resulting from demandoutstripping the capability of a network feeder to supply all the capacity / energy required.Capacity / energy shortfalls from surplus demand were addressed by a combination of renewable (inthis case: hydroelectric, wind, photovoltaic and solar hot water) and fuel-driven (in this case diesel)distributed energy. Ratios of 80%/20%, 50%/50% and 20%/80% RE/DGN were used, and these ratiosrepresent the proportion of capacity delivered by the RE and DGN components when 100% of the REcapacity is available. If the peak capacity shortfall is 100kW for example, for a 50%/50% WTG/DGNsystem, 50kW of WTG is the maximum capacity contribution from the wind (and the assumed nameplate sizing of the turbine) with the peak capacity shortfall balance of 50kW met by the diesel genset.The capacity and energy shortfall requirements were calculated on a half-hourly basis over a 20-yearperiod for each of the load growth scenarios. These figures were converted into monetary valuesusing the network asset valuation reports to derive an annual financial contribution requirement tooperate, maintain and replace the existing feeder. The annual financial contribution to line upgrade /replacement was discounted to provide the NPV marginal distribution cost introduced previously.The total capacity and energy benefit derived from the various combinations of distributed energy (DE)used, covered: (a) line upgrade deferral using RE and DGN; (b) peak distribution capacity shortfall(wholesale) energy contributions from RE and DGN; (c) off-peak (wholesale) energy contributionsfrom RE (don’t want to waste non-peak RE available); (d) transmission peak load reduction at the gridexit point (GXP) from RE and DGN capacity contributions. These benefits were offset by the capitaland O&M costs (including fuel costs) associated with using different DE combinations, and the loss innetwork energy distribution revenue caused by using local DE to meet the demand instead of energyimported from the GXP. The net benefit / cost was derived from the difference between these amounts,and the return on investment (ROI) was derived from the ratio of these amounts. The economicassumptions are summarized below in table 1:Table 1: Key Economic Assumptions for DE Benefits and Fuel Costs Line Upgrade Deferral Value (Capacity-valuation method, MDCC) $99.37/kW/Year Line Upgrade Deferral Value (Energy-valuation method, MDEC) $0.0807/kWh GXP Transmission Savings Value $50.62/kW/Year Energy Wholesale Price $0.1289/kWh Energy Distribution Revenue Loss $0.0687/kWh Diesel Fuel Price and Annual Increase Range $1-$3.00/litre, 2-10%/Year increaseDr. Iain Sanders Sustainable Innovative Solutions Limited Page 5 of 25
  6. 6. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasRuatoria Feeder Case StudyThe Ruatoria feeder (see figure 4) on the Ruatoria substation (see figure 3) was selected for this study(see figure 5). This feeder was selected because it demonstrated an annual increase of peak capacity,and detailed asset management information along with half-hourly demand information was available.Figure 5: Ruatoria Feeder Half-hourly Capacity Profiles for 2001-2003Load Profile History and ProjectionsThe local load profiles are used to enable prediction of DE capacity support opportunities. For threeyears in succession, 2001 to 2003, the average peak capacity growth rate was 1.5% / year. To better Comparison of Peak Load Growth Scenarios and Relationship to the Capacity Threshold for Grid- Support on the Ruatoria Feeder 9,000 8,000 7,000 6,000 Total Load (kW) PEAK LOAD Threshold 5,000 DE REQUIREMENT 1.75% / Yr FOR 10%/YR GROWTH 4,000 5% / Yr 10% / Yr 3,000 PEAK LOAD DE REQUIREMENT 2,000 FOR 5%/YR GROWTH 1,000 PEAK LOAD DE REQUIREMENT FOR 1.75%/YR 0 GROWTH 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Time in YearsFigure 6: Ruatoria Load Growth Scenarios AdoptedDr. Iain Sanders Sustainable Innovative Solutions Limited Page 6 of 25
  7. 7. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasillustrate the potential impact of DE on line upgrade deferral for the more general case, growthprojections of: 1.75, 5 and 10% / year were investigated. A peak capacity threshold of 1,600kW wasselected to illustrate the methodology used, although the exact capacity constraints were not identified.The capacity threshold represents the capacity above which the feeder is overloaded due to voltagedrop, overheating or overloading etc. (see figure 6). We have assumed that the demand profile andload factor do not change over this growth period. Detailed analysis presented here gives the resultsobtained for the 10% load growth scenario to emphasize the potential impacts of DE technologies.Assessing Costs of Network UpgradesIn order to derive the benefit available from installing DE to meet the peak load requirement when thethreshold capacity of the Ruatoria Feeder is surpassed (1,600kW for the purposes of this case study),it is necessary to calculate the line upgrade deferral value of the feeder. The line upgrade deferralvalue is calculated by combining the direct and indirect annual O&M costs of the feeder with thehypothetical cost of reinvestment once existing infrastructure is replaced. The following informationhas been provided by ENL, based upon ENL network data and ENL assumptions made. Direct & Indirect Annual O&M Costs (Derived from ENL Asset Management Plan and ENL Asset Accounting Spreadsheets) Direct Costs = $935 / km / Year Indirect Costs = $66 / Connection / Year FEEDER Length (km) No. of Connections Annual O&M Costs Ruatoria: H. Ruatoria 20.000 333 $40,678.00 Estimated cost of reinvestment once existing infrastructure is replaced (as assessed by ENL) Annual reinvestment cost = {ODRC x 2} / 40 (lifetime) ODRC = Optimized Depreciation Replacement Cost Total Return = Annual O&M Costs + Annual Reinvestment FEEDER Reinvestment / Yr. Annual O&M Costs Total Annual Required Ruatoria: H. Ruatoria $33,350 $40,678.00 $74,028.00The total annual investment required to maintain and upgrade the Ruatoria Feeder has beencalculated to be $74,028. This value was converted into NPV $/kW/year and $/kWh/year amounts,corresponding to the annual energy and capacity demand forecasts predicted over a 20-yeartimeframe for a 10% annual growth rate. The marginal distribution capacity and energy costs (MDCCand MDEC) are summarized below in table 2:Table 2: Key Parameters and Assumptions for Marginal Distribution Capacity and Energy Costs Parameters Value Feeder Capacity Threshold, C(T) 1,600kW Note 1 Network Finite Planning Horizon, n 40 Years Note 2 (Max.) Network Investment Deferral Period, D(t) 20 Years Unity Cost of Capital (Borrowing), r 10% Inflation Rate Net of Technology Progress, i 3% Baseline Diesel Fuel Price and annual increase $1.00/litre (Yr-0), 2%/yr inc. Capacity Deferred by D(t) Years 6,473kW NPV Marginal Distribution Cost (MDC) $739,063.44 NPV MDCC / kW / Year $99.37 / kW / Year NPV MDEC / kWh $0.0807 / kWh Note 3 Net Present Cost of Feeder Distribution / Customer / Day $0.609Note 1: Planning Horizon = Furthest extent of asset investment (max. possible in the model is 100 years).Note 2: Deferral Time = Duration of DE project (1 to 30 years (max.) possible).Note 3: This cost does not include the share of the 50kV subtransmission which is included in the total distribution cost. Because our DEoptions do not effect this cost component, it has not been used in the comparisons.Dr. Iain Sanders Sustainable Innovative Solutions Limited Page 7 of 25
  8. 8. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasAssessing Costs of Network UpgradesThe values in the list above for the net present value marginal distribution capacity and energy cost(NPV MDCC and NPV MDEC): $99.37/kW/year and $0.0807/kWh/year, compare reasonably well withdata from other sources and represent the value per unit capacity and energy per year of deferringdistribution network upgrade by a year via reliable DE peak capacity / energy network-support. Thereare however, costs to the network from introducing reliable DE, and these will reduce the net benefitsof line upgrade deferral. The assumed DE capital and operating (fuel and maintenance) costs aresummarized in figure 7 below and table 2 above. The costs of DE necessary to match the systemcapacity shortfall were derived from the total capacity shortfall using figure 7.The quality of results delivered with the model are dependent on the level of detail provided by theload profile projections, RE supply profiles and other input parameters required. The higher the detail,the better the accuracy of the costs predicted. In this study the renewable energy (RE) and dieselgenset (DGN) supply curves were derived from half-hourly time sequence data derived for a completeyear. These curves are used to establish the amount of DGN and RE generation capacity required tomaintain supply service as the demand grows, without network capacity extensions.That is, local DE supply was used to support the capacity / energy shortfall when capacity / energydemand surpassed the Ruatoria Feeder’s threshold value as identified in table 2. RE was always thepreferred local DE supply option selected to make up for the peak load shortfall, with the fuel-drivenDGN making up the balance. The capital costs assumed for the individual modular units used in thefive DE scenarios selected: (1) hydroelectric power (HEP) with diesel genset (DGN) support; (2) wind turbine generation (WTG) with DGN support; (3) photovoltaics (PVS) with DGN support; (4) solar hot water (SHW) with DGN support; and (5) DGN by itself, are shown in figure 7. Hydro & Wind Capital Cost: O&M = 2% of Capital Cost / Year PV & SHW Capital Cost: O&M = 0.5% of Capital Cost / Year Diesel Genset Capital Cost: O&M = 5% of Capital Cost / Year $100,000 Hydro Wind Capital Cost, $/kW $10,000 Photovoltaic Solar Hot Water Genset Log. (Photovoltaic) Log. (Hydro) $1,000 Log. (Wind) Log. (Solar Hot Water) Log. (Genset) $100 0 1 10 100 1,000 10,000 Size, kWFigure 7: Assumed DE Capital CostsThe modular capacity profiles of the RE resources used in this study (the four RE resources used inDr. Iain Sanders Sustainable Innovative Solutions Limited Page 8 of 25
  9. 9. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasthe five DE scenarios mentioned previously) are shown in the following graphs. With the exception ofHEP, the supply profiles (see figures 10-12) were adjusted by scaling to the peak capacity shortfall.The HEP profiles were derived differently, because the volume of water available in the flow-of-riverresource was fixed (se figure 8). 1/2 Hourly Water Flow (in cubic metres per second) for an Actual River for Day 1 to 182 of a Normal Calendar Year 1 8 15 22 29 36 43 50 57 1,200 64 71 78 1,000 85 Flow (m3/s) 92 99 800 D ay 106 113 of 120 600 Ye 127 ar 134 400 /.. 141 . 148 200 155 162 0 169 23:00 21:30 20:00 176 18:30 0.00-200.00 200.00-400.00 17:00 15:30 14:00 12:30 11:00 9:30 8:00 6:30 5:00 3:30 400.00-600.00 600.00-800.00 2:00 0:30 800.00-1000.00 1000.00-1200.00 Time of DayFigure 8: First Six Months’ Half-Hourly Flow-of-River Hydro Resource Used in the StudyThe HEP supply factor corresponding to the flow-of-river resource used (see figure 8) was related tothe HEP turbine capacity rating (see figure 9). HEP Supply Curve 1.000 0.900 (Average Delivered/Turbine Rating) 0.800 0.700 Supply Factor 0.600 0.500 0.400 0.300 0.200 0.100 0.000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Percentage of Max. Capacity AvailableFigure 9: HEP Supply Factor for Flow-of-River UsedThe HEP supply curve in figure 9 shows the relationship between the average capacity delivered tothe actual turbine capacity rating, based upon the maximum capacity available for extracting from theDr. Iain Sanders Sustainable Innovative Solutions Limited Page 9 of 25
  10. 10. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasriver. If for example, the river can deliver a maximum capacity of 10MW for 2 weeks of the year, andthe HEP turbine rating is 1MW, the average HEP supply capacity available is 0.6 x 1MW = 600kW.The first six months’ WTG supply profile for a 1MW turbine is shown in figure 10 below. This profileassumes an average annual wind speed of 6m/s. 1/2 Hourly Load Profile for 1 MW WTG for Day 1 to 182 of a Normal Calendar Year (Annual Wind Speed = 6m/s) 1 8 15 22 29 36 43 50 57 1100 64 71 1000 78 900 Capacity (kW) 85 92 800 99 700 D ay 106 600 of 113 120 500 Ye 127 ar 134 400 / .. 141 300 . 148 200 155 100 162 0 169 23:00 21:30 20:00 176 18:30 0-100 100-200 200-300 300-400 17:00 15:30 14:00 12:30 11:00 9:30 8:00 6:30 5:00 3:30 400-500 500-600 600-700 700-800 2:00 0:30 800-900 900-1000 1000-1100 Time of DayFigure 10: WTG First Six Months’ Half-Hourly Profile 1/2 Hourly Load Profile for 1 kW PV System for Day 1 to 182 of a Normal Calendar Year 1 8 15 22 29 36 43 50 57 1.00 64 71 0.90 78 Capacity (kW) 0.80 85 92 0.70 99 D 0.60 ay 106 113 of 120 0.50 Y 0.40 ea 127 r/ 134 0.30 ... 141 148 0.20 155 0.10 162 0.00 169 23:00 21:30 20:00 176 18:30 0.00-0.10 0.10-0.20 0.20-0.30 0.30-0.40 17:00 15:30 14:00 12:30 11:00 9:30 8:00 6:30 5:00 3:30 0.40-0.50 0.50-0.60 0.60-0.70 0.70-0.80 2:00 0:30 0.80-0.90 0.90-1.00 Time of DayFigure 11: PVS First Six Months’ Half-Hourly ProfileThe first six months’ PVS half-hourly profile for a 1kW system is shown in figure 11. The profile usedwas derived from best fit solar data for the East Coast region and also applied to produce the SHWDr. Iain Sanders Sustainable Innovative Solutions Limited Page 10 of 25
  11. 11. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areasprofile in figure 12.The solar hot water profile is significantly different to the PVS profile because it is assumed thatelectrical 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 in many parts of New Zealand).This would not be the case for all time periods in the year, but is an adequate approximation becauseit would certainly be the case during peak load periods. Heating Profiles Contributed by a 4m2 Solar Hot Water System 0-0.5 0.5-1 0:00 1:00 2:00 3:00 1-1.5 1.5-2 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 2 Time of Day 14:00 kW Electrical Hot Water Equivalent 15:00 1.5 16:00 17:00 1 18:00 0.5 19:00 20:00 0 21:00 D N ec O o 22:00 S e ct v A p J ug J ul 23:00 M un Ap ay M r F ar Month of Year J an ebFigure 12: SHW Contribution to Electrical Heating DemandIt is worth mentioning at this point the quite negative impact that SHW investment has on networkcosts. SHW results in lower energy sales for the same network capacity requirements. This can besubstantial since water heating represents 25-35% of residential energy demand.As identified in the introduction, a basic principle for the analysis is that DE must provide the samelevel of reliability as network supply. Thus is achieved by matching the capacity requirement one forone with fueled generation (DGN), irrespective of the level of intermittent renewable technologyinstalled.The five DE scenarios selected: (1) hydroelectric power (HEP) with diesel genset (DGN) support; (2)wind turbine generation (WTG) with DGN support; (3) photovoltaics (PVS) with DGN support; (4) solarhot water (SHW) with DGN support; and (5) DGN by itself; matched continuous half-hourly energydemand with the supply available from each of these scenarios. The net cost-benefit of each of theseDE scenarios on the Ruatoria Feeder for line upgrade deferral was determined. The following DEcosts were included: capital investments, maintenance, operating costs and fuel costs etc. to calculatethe net present value (NPV) of both the renewable and fuel-based DE options.The following DE benefits were included (as introduced in table 1) to calculate the NPV of both therenewable and fuel-based DE options. • line upgrade deferral: $99.37/kW/Year or $0.0807/kWh/Year; • transmission savings: $50.62/kW/Year peak GXP load reduction;Dr. Iain Sanders Sustainable Innovative Solutions Limited Page 11 of 25
  12. 12. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural Areas • grid-supporting energy production: $0.1289/kWh; and, • non-grid-supporting energy production ($0.1289/kWh/Year) less loss of distribution earnings ($0.0687/kWh/Year) to the network from using local energy.NPVs were calculated over a 20-year project lifecycle, assuming a 10% utility cost of capital interestrate, and a 3% inflation rate net of technology progress. The RE-DGN mix was fixed at the followingpeak capacity (name plate rating) ratios in this study: 1. 20%/80% DGN/RE, 2. 50%/50% DGN/RE, 3.80%/20% DGN/RE, and 100% DGN (scenario five). The RE generation capacity was selected toensure it met 20, 50 or 80% of the peak load shortfall when delivering 100% of its name plate capacityrating (sizing).Alternative Line Upgrade Deferral MethodologiesTwo different line upgrade deferral valuation methodologies were used in this study to calculate theNPV derived from DE technologies: capacity and energy. Both methods calculated the networkcapacity requirements from DE for every half-hour over a 20-year period.Method 1: capacity valuation – values the line assets or any alternative generation (DE) options –based upon the peak (maximum) capacity delivered by the assets each year; and, method 2: energyvaluation – values the line assets or any alternative generation (DE) options – based upon the total(sum) energy delivered by the assets each year. The net lifetime benefit from each method for lineupgrade deferral is compared in figure 13. Comparison of Net Benefit from Capacity-Driven vs. Energy-Driven Line Upgrade Deferral $8,000,000 $7,000,000 Relates to energy supplied only during peak $6,000,000 periods related to grid-support $5,000,000 NPV for Lifetime Benefit $4,000,000 Distribution feeder peak load Peak Disc. Distribution (kWh) Peak reduction period kWh Disc. Grid-Supporting Energy (kWh) $3,000,000 period kW corresponding to energy Disc. Trans. Saving (kW) capacity GXP peak load valuation Disc. Upgrade Deferral (kW) $2,000,000 valuation reduction for line for line upgrade upgrade $1,000,000 deferral deferral $0 Distribution kW-Focus kWh-Focus revenue lost -$1,000,000 Line upgrade deferral value Line upgrade deferral value based on kW capacity valuation based on kWh energy valuation -$2,000,000 methodology methodologyFigure 13: Comparison of Capacity Valuation (Method 1) and Energy Valuation (Method 2) for Line Upgrade DeferralFigure 13 shows that the dominant value from DE in this situation is for line upgrade deferral,representing 78% for capacity valuation and 85% for energy valuation. The difference in value isattributed to the difference in impact of NPV discounting on the variation in energy and capacitybenefits during the 20-year line upgrade deferral project lifetime. A substantial increase in energyvalue from line upgrade deferral in latter years is not offset by NPV discounting to the same degree asthe capacity value. The NPV of capacity-driven line upgrade deferral benefits is greater in the earlyyears, while the NPV of energy-driven line upgrade deferral is greater in the latter years. Overall, theenergy NPV over the 20-year project lifetime is greater than the capacity NPV.Dr. Iain Sanders Sustainable Innovative Solutions Limited Page 12 of 25
  13. 13. Distributed Energy Investment as an Alternative to Distribution Upgrades in Rural AreasIt has been observed that method 1: capacity valuation, is more beneficial to fuel-driven DE systemswith low capital costs (i.e. DGN by itself), and method 2: energy valuation is more beneficial to RE-driven DE systems with unpredictable delivery of capacity needs. Capacity valuation benefits fuel-driven DE systems more because energy is only provided to supply capacity needs for peak loadreduction. Peak load reduction may typically involve long narrow (sharp) spikes with little energycontent. This scenario is ideal for network companies operating diesel gensets for only a few hours ofthe year. Energy valuation is better for customer-driven renewable energy contributions that cannot beswitched on and off “on tap” like a standby generator. Energy valuation notes and values theaggregate contribution of individual RE options over the year when capacity-support from a particularRE technology may vary anywhere between 0 and 100% for different (peak load) time periods.Results from the Ruatoria Feeder Case StudyA comparison of the RE-DGN cost-benefits is given in figure 14 below, with the NPV benefits shown inblue besides the NPV costs shown in red for each scenario investigated. The bar chart shows the REcosts / benefits on top (brighter colours) of the DGN costs / benefits (lighter colours). Renewable Benefit – Cost of distribution Comparison of Net-Benefits and Net-Costs from Various RE-Genset Combinations revenue Renewable Cost loss $10,000,000 $9,000,000 $8,000,000 NPV of Benefit / Cost $7,000,000 $6,000,000 $5,000,000 $4,000,000 $3,000,000 $2,000,000 $1,000,000 $0 Genset Benefit it fit fit t fit it t fit it t fit it it it it st r o ost st t st t en it W ost t W ost t os os os os os os ef ef ef ef os ef ef ef 0H ene 0H ene ef ne ne ne 0P Co 0P Co 0P Co – Cost of 0H en 0W o C 0W ro C 0W ro C en en en en en en C C C en C 0S V C C C Be Be Be B B B W 0H W W d d d B 0S V B B 0S V B B B B r in in in distribution /8 0P P /2 0P ro yd yd ro yd H H H d d d V V V W en 0G W 0W W 50 in in in 0S 0S 0S yd yd yd 8 2 H H H 0G 20 /80 80 /20 n/ n/ n/ revenue 10 H 0H /8 /8 /5 /5 /5 /2 /2 /8 50 n/5 80 n/2 20 Ge 50 Ge 80 Ge 80 10 en en en en en en en en en /8 /5 /2 /5 en /5 /2 e e loss en en en / 20 en 50 en 80 en G G G G G G G G G en en en G G G 20 20 50 50 50 80 80 G G G G G G 20 50 80 G G G 20 20 50 80 Genset Cost RE-Genset CombinationFigure 14: RE-DGN Cost-Benefit AnalysisFigure 14 shows that for this baseline case of low fuel inflation (2%/year), the greater the DGNcomponent in the total RE-DGN mix, the lower the NPV lifecycle cost of the system installed. Only twoDE systems are shown to make a net loss: the 20%/80% DGN/PVS and the 50%/50% DGN/PVS, dueto the large capital costs incurred with installing the PVS system (see figure 7). Figure 15 comparesthe annualized Return on Investment (ROI) from having invested in the different RE-DGNcombinations shown in figure 14 above.Figure 15 shows that under current costs for operating gensets in New Zealand (assuming a$1.00/litre price for diesel (or any other fuel producing the same electrical output), increasing at anaverage fixed rate of 2% per year), scenario 5: DGN by itself (0%/100% RE/DGN) represents the mostbeneficial option for DE line upgrade deferral on the Ruatoria Feeder.While renewable DE without carbon credits appears to be less attractive than diesel generation,distributed renewable energy (RDE) coupled with firm capacity from fuel-based generation such asdiesel gensets (DGN) still offers a substantial strategic benefit over conventional expansion of theDr. Iain Sanders Sustainable Innovative Solutions Limited Page 13 of 25

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