A PROPOSED WAY FORWARD TO DEAL WITH ELECTRICITY SUPPLY AT STEWART ISLAND
Prepared by: Robin McNeill Enterprise Project Manager Venture Southland
For: Southland District Council
3 August 2007
Robin McNeill o BA, BE(Hons)(Elect), SMIEEE, MIPENZ, CPEng, IntPE(NZ) File N . 940/15/10/1 Enterprise Project Manager Venture Southland [email protected]
3 August 2007
A proposed way forward to deal with electricity supply at Stewart Island
Executive summary ...... 2 1. Introduction ...... 3 2. Background ...... 3 3. Existing power network ...... 4 4. Economic, intangible and engineering considerations ...... 5 5. Electricity generation options for Stewart Island ...... 8 6. Energy storage ...... 20 7. Summary of generation and storage options ...... 27 8. Demand side management ...... 28 9. Proposed course of action ...... 29 10. Activities ...... 31 11. Budget and funding ...... 32 12. Acknowledgements ...... 33 Appendix I. Location and land status maps ...... 34 Appendix II. Electricity demand ...... 36 Appendix III. Regulations pertaining to SIESA ...... 38 Appendix IV. Network diagram ...... 39 Appendix V. Storage dimensioning and costs...... 40 Appendix VI. Hydro power catchments ...... 41 Appendix VII. Net Present Value calculations for diesel and wind generation ...... 42
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Executive summary At close to 52 cents per unit, electrical energy on Stewart Island costs nearly three times that on mainland New Zealand. This report reviews alternative ways to provide electricity to Stewart Island with the intention of reducing the cost of electricity to consumers. It concludes that a wind generator coupled with either hydrogen, or battery storage, at a cost of $1.9 million, would be cost effective, subject to confirmation of sufficient wind availability and velocity.
Provided that a capital outlay to build and install a wind generator and storage system could be obtained, the direct cost of generating electricity on Stewart Island could be halved. Actual reductions that could be passed on to consumers would be less than that due to significant overheads inherent in operating the network.
There has been a significant change in electricity utilisation on Stewart Island as a result of the fishing industry being replaced by tourism over the last ten years. As a result, there remains considerable uncertainty in future and suppressed demand for electricity and the likelihood of continued and augmented electricity substitution, such as home insulation, double glazing and solar hot water heating.
There are also intangible attractions for adopting renewable electricity generation on Stewart Island. These include matching the increasingly pervasive “green” commitment within New Zealand, alignment with the Government‟s ambitions for greenhouse gas neutrality and empathy with the growing eco-tourist industry.
This report recommends that detailed study now be undertaken to: Confirm that Ackers Point, Ryans Creek, Deep Bay and Garden Mound are suitable sites for establishing wind turbines and select the most appropriate site, Examine in detail the merits and costs of hydrogen and battery energy storage, Model grid stability, Evaluate future electricity consumption and substitution, Install grid connected solar electricity generation on Department of Conservation buildings for real-world evaluation.
This report also recommends that:
On behalf of the Stewart Island community, Venture Southland seek funding of $138,400 to carry out these studies and trials, Venture Southland closely monitor Government greenhouse gas initiatives and developments that could benefit Stewart Island, Venture Southland, working closely with SIESA, project manage the proposed studies, Venture Southland further evaluates ownership models and funding that could provide the necessary capital to implement new generation initiatives, Venture Southland investigate opportunities to assist with retrofitting houses on Stewart Island with insulation, double glazed windows and other energy efficiency measures, Venture Southland investigate the feasibility of Stewart Island progressing towards having a “zero-carbon footprint”.
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1. Introduction
Stewart Island has around 440 permanent electricity consumers connected to a network powered by five diesel generators at a central power station at Hicks Road. The retail cost of electricity on Stewart Island is $0.46/kWh plus GST ($0.5175/kWh) for Standard Rate and $0.40/kWh plus GST for Night Rate i , the latter only being available to commercial customers. The high prices are considered to be untenable by many Stewart Island inhabitants. Consequently, seeking ways to reduce the cost of service has provided the impetus to review the electricity supply options for Stewart Island, including electricity substitution.
Demand for electricity has been changing since 1988, when the present network was commissioned and when Stewart Island was primarily a fishing town, to the present day. This has arisen from the Stewart Island economy moving to become tourism based and with a significant number of dwellings only being used in the summer months. This has resulted in the peak loads now occurring at the start and finish of the tourist season.
The cost of operating the current power system is very sensitive to increasing oil prices and is high enough to make alternative generation sources appear viable. In addition, Government‟s recently announced ambitions for greenhouse gas sustainability and the creation of greenhouse gas credits may well make renewable forms of electricity generation even more attractive.
The purpose of this report is to set out a strategy to reduce the cost of generating and the price of purchasing electricity on Stewart Island, preferably through using sustainable energy sources. This report:
sets out the background to the current energy consumption on Stewart Island, discusses market dynamics and demand variability identifies and discusses the most likely options for sustainable electricity generation in Stewart Island, suggests further research projects to confirm those sustainable generation methods, provides a budget to undertake such research projects, suggests possible project funding options.
This report makes no effort to investigate alternative funding or ownership models for providing electricity or electricity substitution for Stewart Island. The assumption is made that, at least to a first approximation, the real cost of purchasing electricity on Stewart Island will be independent of the commercial arrangements unless subsidisation from outside of Stewart Island occurs.
2. Background
Over the last thirty years or so, various studies by Government and the private sector have investigated how to best provide electrical supply to Stewart Island. Some of the studies themselves are no longer available, but their findings are within current institutional knowledge and have been included in this report.
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In response to requests from the Stewart Island Community Board and Southland District Council, in August 2006 Venture Southland issued a Request for Proposals for a Review of Electrical Power and Energy Options for Stewart Island. The objective of this review was to consider and evaluate all possible supply-side and demand-side indigenous sources of energy to augment, or substitute that provided by the Stewart Island Electrical Supply Authority (SIESA). These included distributed generation (DG) and remote area power supplies (RAPS), including but not limited to micro-hydro, solar hot water, solar photo-voltaic, wind, small diesel generators, biomass/biofuel, wave, tide and hybrid systems.
Those initiatives which were seen to be practicable were to be further analysed, taking into account logistics, social acceptance including RMA considerations, regulatory requirements, electricity network stability and funding. Economic, regulatory and infrastructural barriers to adoption of indigenous sources of energy were also to be examined with suggestions proposed to overcome them.
Bids were submitted by:
1. Energy3, who were keen to supply a second hand wind turbine, 2. Energy and Technical Services, and 3. Kordia.
Two subsequent bids were received from:
1. Sinclair Knight Merz, and 2. Hydro Tasmania Consulting.
All of the bids were considered in depth, but for a variety of reasons all were rejected as unsuitable. The stronger bids were also found to be well beyond the available budgetii.
In the mean time, EECA had been approached with respect to obtaining additional funding to carry out this research. They were quite keen to assist with funding an analysis of possible solutions for Stewart Island and will be approached for assistance with the next phase of this project.
By late February 2007 it became clear that a more pragmatic, affordable line of investigation was required. The most useful way to prune investigation costs was considered to be for Venture Southland to utilize in-house expertise to undertake a preliminary analysis and identify key factors and so identify practicable generation and substitution solutions for more detailed, expert study. Such a report would thus provide a basis from which to engage subject matter experts and to use as a supporting document in seeking funds to carry out this work. The remainder of this report addresses this redefined focus.
3. Existing power network
The Stewart Island power supply, including lines and generation, is provided by the Stewart Island Electrical Supply Authority, SIESA, which is owned by the Southland District Council. The network became operational in 1988.
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The Invercargill based power-lines company PowerNet was contracted to run the technical aspects of the island‟s supply in 2005. Continuity Contracting has been sub- contracted by PowerNet to carry out the work in support of the contract. The cost to manage and run SIESA, including provision of technical operating staff, is approximately $280,000 per year. This is over half of the current annual diesel cost of $480,000 per year.
The electricity network comprises of some 19 kilometres of 11 kV overhead wiring and four kilometres of 400 V and 230 V overhead and underground wiring. There are some thirty 11 kV / 400 V - 230 V transformers. The Stewart Island network diagram is shown in Appendix IV.
The Stewart Island power station is at Hicks Road, off Horseshoe Bay Road (See Appendix I). Five diesel generators, with a fifth on standby, supply the average peak load of around 400 kilowatts and which are proving expensive to operate. The peak demand month is usually January and there is a steady growth in demand, as set out in Appendix II.
The regulations pertinent to SIESA‟s operation are set out in Appendix III.
4. Economic, intangible and engineering considerations 4.1. Carbon credits
Each litre of diesel consumed by the existing generators produces 2.7 kg of CO2. The current price of carbon offset credits is between $15 and $30 per tonne; very roughly one hour‟s operation of the present generators at full rating.
People, or organisations can claim to be carbon neutral when they measure and reduce the greenhouse gas emissions associated with their activities (which come about mostly when fossil fuels are burnt to generate electricity or as transport fuel), and then undertake 'offset' projects to remove an equivalent amount of carbon dioxide from the atmosphere, or prevent it being released. This offsetting process is sometimes referred to as buying carbon credits.
The Prime Minister‟s Statement at the opening of Parliament on 13 February 2007 outlined a number environmental initiatives that will accelerate New Zealand‟s sustainable development. A key effort is for the Public Service to take the lead in becoming carbon neutral with a lead group of six agencies having carbon neutral plans in place by early 2008. Full details were announced in Budget 2007.
It is anticipated that any electricity supply for Stewart Island through renewable energy sources could be made more economic by selling the carbon credits as offset funding to another agency, or on the market. This is currently not straightforward and it could be until later in 2008 before Government sanctioned trading schemes become viable, if at all. In the mean time, trading on the so called “Grey Market” to Meridian, Landcareiii and others may be possible and the New Zealand Stock Exchange has proposed that a “cap
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and trade” carbon board for 2008. At present, the only government interest in carbon credits is for permanent forestation.
Stewart Island is not well situated to take advantage of active carbon sequestration as there are very limited sites available for new, permanent forestry. Mitigation technologies such as underground sequestration are neither mature, nor practicable on Stewart Island.
4.2. Intangibles
As noted elsewhere in this report, Stewart Island has undergone a significant economic shift over the last ten to twenty years as tourism has become the prime income source. Notwithstanding, tourism on Stewart Island is currently at a modest level compared to some other tourism attractions in the Southland region, although its uniqueness is recognised. In short, Stewart Island‟s key tourism appeal centres on being synonymous with Rakiura National Park and being “eco-friendly”.
Themes and images identified in the Southland Tourism Strategyiv as being central to Stewart Island tourism are: life on a southern island; nature; unique coastal environment; and remote and rugged wilderness. The report asserts that sustainable tourism development is demanded by the markets that Southland is targeting and in this sense, the opportunities to showcase sustainable tourism ventures can be explored to Southland's advantage.
To replace the fossil-fuel powered engine-alternators that currently provide Oban‟s electricity with “green”, renewable alternatives such as bio-diesel and wind generation would fit neatly within the wider ambit of sustainable tourism. Informal discussions with a wide range of people indicate that there is widespread appeal to making Stewart Island‟s electricity completely renewable and so minimise, or even eliminate the island‟s “carbon footprint”.
While it is technically possible to provide all energy, including electrical energy on Stewart Island from renewable energy sources, some sort of subsidisation would likely be necessary to achieve this goal. Nonetheless, this need not be an unachievable goal and needs to be further explored.
4.3. Network ownership implications
As outlined earlier, the Stewart Island network lines and generation plant is owned by the Southland District Council. The only other network in New Zealand where the generators and network are owned by one entity is in the Chatham Islands.
Single, community owned ownership provides significant simplicity in managing and operating the network and generators for no independent lines companies and generators are involved. This allows the network to be planned and managed in its totality to arrive at an optimal operation.
By way of comparison, connecting to the national grid and exporting electricity into the national grid are two different activities and both require negotiations with a variety of
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bodies and the means to do this are not altogether clear and the results seldom seem to be advantageous to the exporter.
4.4. Economic implications of connection
A complicating feature of the SIESA network is that some ten customers account for half of the customer load (see Appendix II). Should these customers decide to generate their own electricity, the overheads to the network would fall more heavily on the remaining, small customers. It is possible that some of these key customers could consider adopting co-generation, which may be overall energy efficient, but could create some financial difficulties for SIESA.
Any new interconnect tariffs for grid-connect systems would need to recognise the utility to the end user of having the main grid and generators available to back-up the renewable energy system. Additionally, care would need to be taken to ensure that the interconnection tariff was properly set.
To this end, further investigations- most likely attached to a proposed demand side study- should be undertaken to confirm the commercial risk inherent to the network by having so few key, base load customers and also to review the tariffs so that any risk is minimised and that the appropriate market signals reach all customers.
4.5. Grid stability
Keeping the voltage supplied to consumers within 5% of 230Vrms for single phase supplies and 400Vrms for three phase supplies, with a frequency of 50 Hz is known as grid stability. Grid stability is important to ensure longevity of electrical equipment and, indeed, its survival. Keeping the grid stable so that, in particular, there are no uncontrolled fluctuations in voltage is also necessary to prevent generators tripping out of service and causing blackouts to occur.
Managing grid stability is never a trivial problem, especially for small networks where even small changes in load can be significant for there are insufficient consumers to average out individual changes in demand. When renewable energy generation is used the problem is compounded by the often highly variable nature of the generation output. By comparison, large power grids, such as on mainland New Zealand, have sufficient generating inertia so that sudden changes in loads, bringing generators online, or removing generators from the network cause only negligible changes to the network operating parameters.
Possible ways to manage grid stability include switching in dummy loads (which could be utilised to heat the local swimming pool), spinning flywheels and electronic reserve. Where they can be used, hydro schemes using Pelton wheel generators are intrinsically very responsive and are thus well suited to assist grid stability. Unfortunately, as is discussed later, use of Pelton wheel generators are not appropriate for use on Stewart Island.
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The operating parameters for small networks that involve renewable energy generators are unique to each network and so this aspect of the network for Stewart Island will need careful examination should renewable energy generation be adopted.
5. Electricity generation options for Stewart Island
The geography of Stewart Island, the location of Oban and the size of Rakiura National Park all restrict the range of potential renewable power supplies. The costs of undertaking engineering works on Stewart Island are much higher than in mainland New Zealand because of transport limitations, isolation, a lack of building aggregate and a very confined road network that is not designed for heavy vehicles. Even in the township of Oban, native bush predominates. As a result, building major power lines, or undertaking civil engineering works of any kind is very expensive. That aside, much of Stewart Island is contained in Rakiura National Park which, unless overwhelming benefits can be demonstrated, is unavailable for engineering works of any sortv.
A further difficulty with maintaining any electricity generation on Stewart Island lies in its remoteness. Access to Stewart Island is very weather dependant and occasionally aircraft flights and ship sailings are delayed for days. This has significant ramifications for technologies installed there as on occasions the few general purpose technicians living on the island will provide the only source of expertise to clear faults and spare parts may take some days in arriving.
All these factors are significant in narrowing the range of options to those discussed further in this section.
5.1. Hydro generation
Analysis of potential sources of hydro power on Stewart Island was undertaken by Robin Webb of ER Garden & Partners and Royds Sutherland McLeay for the Ministry of Works and Development in 1982vi. The study found that the only potentially useful source of hydro power could be obtained by building a 35 metre dam near the mouth of the Toitoi River and linking it to Halfmoon Bay with 21 kilometres of aerial cable and 7 kilometres of undersea cable. The cost in 1981 to establish a 1.5 MW generator was estimated to be $7.5 million (in excess of $25 million in present day dollars). TH Jenkins & Associates undertook a hydro electric power potential survey in 1978 for McConnel Dowel Ltd with similar results. The location of the hydro catchments studied are shown in Appendix VI.
Toitoi River lies within the Rakiura Maori Land Trust land and the transmission line would traverse Rakiura National Park. Much of the Toitoi wetlands lie within the Toitoi River Special Management Area, which effectively gives the area protection higher than the surrounding national park. Obtaining consents to establish the dam and the transmission line would be very difficult and widespread opposition could be expected.
The 1982 study also considered, amongst others, a scheme at Maori Beach, which has the advantage of being reasonably close to Oban. With an estimated mean annual flow of 0.3 m3s-1, a hydro electricity scheme there was predicted to produce 24 kW. This is too small to consider for a public scheme.
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The 1982 study did not consider using even closer Mill Creek as it was considered reserved for the town water supply. Energy has been extracted from this creek in the past; the creek is named after a wood mill that was powered by water dammed in the two creeks which go by the same name. The estimated mean annual flow is around 0.2 m3s-1 and thus utilising the possible 40 metre head is capable of providing less than 60 kW. This is too small to consider viable for a public scheme.
Hydro generation is not practicable.
5.2. Wind
The average minimum wind speed for a wind farm is generally agreed to be no less than 8 ms-1. Accepted rules of thumb put wind generator availability at between 35% to 45%, but more detailed analysis is required to confirm any given site.
The power available from wind is proportional to the cube of the wind speed, e.g. a site with an average wind speed of 9 ms-1 has the wind resource to generate more than twice as much electricity as a site with 6 ms-1 average wind speed. Care in choosing a site with a wind speed as high as possible is thus critical to ensure sound performance. The wind characteristics for any site tend to be localised and so it is unwise to extrapolate the performance from one site to another.
NASA Surface meteorology and solar energy available tables for latitude 47˚S and longitude 168˚E vii indicate promising wind performance (see Table 1 and Figure 1) and it is thus likely that an unimpeded site could have good availability. The NASA tables indicate that the prevailing wind comes from 290˚N to 310˚N and on average from 293˚N (west-nor‟west).
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual 10 m 6.19 6.30 6.41 6.89 7.14 7.02 6.63 6.59 6.61 6.56 6.27 6.11 6.56 50 m 7.84 7.98 8.11 8.72 9.03 8.88 8.39 8.34 8.36 8.31 7.94 7.74 8.30 Table 1. Ten year average monthly averaged wind speed at 10 m and 50 m above the surface of the Earth at Stewart Island (ms-1). (after http://eosweb.larc.nasa.gov/sse/).
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100% 90% 80% 19 - 25 m/s 70% 15 - 18 m/s 60% 11 - 14 m/s 50% 7 - 10 m/s 40% 3 - 6 m/s 30% 0 - 2 m/s 20% 10% 0%
Jul Jan Feb Mar Apr May Jun Aug Sep Oct Nov Dec Annual
Figure 1. Monthly averaged percent of time the wind speed at 50 m above the surface of the Earth is within the Indicated range at Stewart Island (%). (after http://eosweb.larc.nasa.gov/sse/).
A weather station connected to the Internet has been operating at Oban since February 2006. The site is at the SDC office and so is not in a good place to provide any robust data . A cursory analysis of the data from this station indicates that the monthly average wind speed is in the order of 2 to 4 ms-1.
Measurements of wind speed were taken at Back Road between March 1994 and January 1995 (see Figure 2). Details of the actual measurement methodology are not available, including the height of the measurements, though the tower is understood to have been less than 5 metres high. The measured average wind speed was just over 3 ms-1 and 70% of all winds speeds were below 5 ms-1. This data is specific and little more information can be drawn from the data other than Back Road is not a good site for a wind turbine. The wind data for Back Road does not predict possible performance for other, more exposed sites on Stewart Island which can be expected to be significantly more promising.
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100%
90%
80%
70% > 19 m/s
60% 15-18 m/s
50% 11-14 m/s
40% 7-10 m/s
30% 3-6 m/s
20% 0-2 m/s 10%
0%
7/03/1994 4/08/1994 1/01/1995 26/04/1994 15/06/1994 23/09/1994 12/11/1994 20/02/1995
Figure 2. Measured wind speed at Back Road, March 1994 – January 1995. Note that the average wind speed should be above 8 ms-1 for a wind farm.
Outside of Rakiura National Park and Rakiura Maori Land Trust lands, which because of their location are too expensive to consider for wind, any wind turbine will need to be located in areas zoned under the District Plan as “Coastal”. Here, under Rule COA2, all buildings and structures are discretionary and providing that public acceptance was able to be gained, it would be possible to erect wind turbines anywhere outside of the built up part of Oban.
The only practicable and possibly publicly acceptable locations identified for wind turbines are:
Ackers Point, between Jensen Bay and Whale Corner Ryans Creek, south-west of the airfield Deep Bay Garden Mound
These sites have a useful proximity to access roads and are likely to have good wind flows. These sites are also within practicable distance of Oban where the major power consumers are. See Appendix I for these locations.
Should a viable wind solution be available, special consideration will need to be given to ensure that the likely gusty conditions that could be encountered on Stewart Island are allowed for in the wind turbine design, selection and installation. Further consideration would also need to be given to the practicalities of transporting and erecting a wind turbine at Stewart Island. Two bladed turbines and their nacelle can be assembled on the ground, while a three-bladed turbine must generally be assembled in situ, requiring
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large cranes and equally wide access roads- which may not be practicable, or affordable.
Windflow Technology Ltd has advised that it would cost in the order of $1M to supply and install one of their 500 kW, 30 metre hub height Windflow 500 turbine. Windflow estimate that it would cost around $50,000 to transport the turbine and tower to Stewart Island.
Micro-wind power, in which small wind turbines with rotor diameters of around 1 metre areployed could be used to provide distributed energy. Typical performance figures are shown in Figure 3 andFigure 4. A fundamental problem is that many houses on Stewart Island are built in sheltered areas. Given that the average wind speed at the SDC office is between 2 ms-1 and 4 ms-1 and that at Back Road the average wind speed is below 5 ms-1, a micro-wind turbine rated at 400 W is going to produce less than 50 W most of the time, i.e. a little over 10% of its rated capacity. This is not promising.
Figure 3. Power output for a typical micro-wind turbine. The upper limits are for non- turbulent sites and the bottom line for turbulent sites. (after Independent Powerviii)
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Figure 4. Energy output for a typical micro-wind turbine (after Independent Powerix)
5.3. Solar
The freely available surface meteorology and solar energy data published by NASA‟s Earth-Sun System Division, Applied Sciences Program, which has data sets for the entire globe at one degree resolutionx, is designed for modelling both solar hot water and solar photo-voltaic (PV) electricity generation. Initial perusal of the NASA data shows that even in winter there is sufficient insolation to make solar energy potentially attractive for hot water heating (demand side electricity substitution) and electricity generation (See Table 2). It should be noted that different makes and types of solar systems perform differently under different conditions and so these figures can only provide an indication of the potential that can be realised.
Tilt Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual angle Avg. 0˚ 5.14 4.29 3.20 2.07 1.20 0.88 1.04 1.80 2.91 4.07 5.05 5.64 3.10 32˚ 4.97 4.47 3.69 2.79 1.85 1.48 1.71 2.63 3.57 4.39 5.03 5.36 3.49 47˚ 4.56 4.23 3.66 2.91 2.01 1.65 1.89 2.82 3.62 4.22 4.67 4.86 3.42 62˚ 3.98 3.81 3.45 2.89 2.07 1.73 1.97 2.85 3.48 3.86 4.09 4.19 3.19 90˚ 2.68 2.69 2.65 2.45 1.88 1.62 1.82 2.51 2.79 2.79 2.74 2.77 2.45 Opt. 5.20 4.51 3.70 2.92 2.07 1.73 1.97 2.86 3.62 4.40 5.17 5.67 3.65 Opt. 11˚ 22˚ 36˚ 52˚ 62˚ 67˚ 65˚ 58˚ 43˚ 27˚ 16˚ 8˚ 38.9˚ angle Table 2. Monthly averaged daily radiation incident on an equator-pointed tilted surface, RETScreen Method (kWhm-2day-1.) Diffuse radiation, direct normal radiation and tilted surface radiation are not calculated when the clearness index (K) is below 0.3 or above 0.8. (after http://eosweb.larc.nasa.gov/sse/).
Modelling needs to be undertaken to confirm the viability and practicability of solar hot water heating and photovoltaic electricity generation. To a first approximation, freely available RETScreen software from Natural Resources Canada xi provides a
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straightforward modelling tool that can be used to determine initial estimates of cost effectiveness for renewable energy generation solutions.
Solar photovoltaic electricity generation
Recent research on four grid connected solar photovoltaic schemes of differing sizesxii indicates that in Canterbury 1100 kWhr of electricity can be exported into a grid system for every nominal kilowatt rating claimed by the solar panel manufacturer. In Oban, the output could be expected to be de-rated to around 1000 kWhr per rated kilowatt. Solar photovoltaic panels typically have a 20 year guaranteed lifetime, at which time performance is typically predicted to be 80% of the rated output.
As a rough rule of thumb, solar photovoltaic panels cost $10,000/kW in New Zealand. Low cost Chinese panels can be purchased for $6,000/kW landed for orders of 40 kW or more.
Indicative prices for installed systems, complete with customer training are set out in Table 3. An open tender to supply and install systems under a supply contract could be appropriate and would likely result in better prices.
System size Installed price Cost per installed (kW) (excl gst) Watt 1.5 $20,000 $12.8 2.0 $23,000 $11.5 3.0 $35,000 $11.5 4.0 $42,000 $10.5 Table 3. Indicative solar PV grid connected prices.
Over an expected 20 year equipment life, a 4 kW system can be expected to produce some 80,000 kWhr of electricity. Net present value calculations yield a price of $0.53 per kWhr for a 0% discount rate and $1.24 per kWhr for a 10% discount rate.
Assuming an installed cost of $10.00 per kW, allowing for an average generation capacity of 500 kW, an estimate for providing all electricity from solar will cost around $5 million. Storage will also be required.
The most practical way to establish solar electricity generation and (through solar hot water) electricity substitution is by way of distributed generation schemes where the panels are mounted on building roofs rather than at a central site. Distributed panels have the advantage that any shading from passing clouds will only affect some arrays at a time and so mitigate the effects on the grid.
In practice, distributed systems would consist of home-owners and local and central government departments installing solar panels on the roofs of the buildings they occupy. The relative merits of centralised and distributed storage are not discussed in this report, but it is likely that a combination of both would be useful.
The Department of Conservation is the only one of the Government‟s six key carbon neutral implementation agencies with an operational mandate and so is likely to be in a
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good position to become involved as a partner for trialling renewable energy generation. The DoC Area Manager Southern Islands has undertaken to investigate grid connection for DoC houses and buildings on Stewart Island. If progressed, such installations would provide valuable information as to the practicalities and performance of grid connected photo voltaic panels in real life as opposed to speculative desk-top studies.
Solar hot water electricity substitution
Solar hot water systems are now considered economically viable in New Zealand, with reputable installed solar hot water systems costing between $4,000 to $7,000 and typically save around 2,500 kWhr per year in electrical heating. In mainland New Zealand they are typically considered to provide a 6 to 10 year to payback on capital investment. For a typical $6,000 solar hot water heating system with a 20 year design on Stewart Island, net present value calculations yield an equivalent price of $0.12 per kWhr for a 0% discount rate and $0.28 per kWhr for a 10% discount rate.
The actual amount of equivalent substituted energy generated by a hot water solar system depends very much on the habits of individual householders. Many of the more reputable brands of solar hot water systems can be retrofitted to existing domestic hot water systems.
Andy Roberts, Area Manager Southern Islands, of DoC has undertaken to investigate solar hot water systems for DoC houses and buildings on Stewart Island.
5.4. Marine energy
Three sorts of marine energy are possible: wave, tide and tidal current. There are currently no commercial wave, or tidal current energy devices in operation although European governments are committing significant resources over the next three to five years. The initial cost of marine energy devices is likely to be higher than other generation technologiesxiii. The generators currently being evaluated are all in prototype stage and have not been scaled up to full size and developed an operational track recordxiv. In short, while marine energy could be applicable in 10 to 15 years time, it would be a high risk investment for Stewart Island.
That said, a number of venture capital marine energy generators are currently being considered for New Zealand and the South Coast and Bluff are areas being considered as potential marine energy test sites. These evaluation opportunities may accelerate marine technological development which could favour possible deployment to Stewart Island.
The Ministry of Economic Development is responsible for the $8M contestable “Marine Energy Deployment Fund” proposed in the draft New Zealand Energy Strategy. The timings and criteria for using this fund are still in development, but an announcement could be made in late 2007. Indications to date suggest that the fund would be used for existing technologies and that preference may be given to a remote island location where diesel power is used. For this reason, while marine generation is likely to be normally too expensive to use, a subsidy from the fund could make it economic. Alternatively, a subsidised system could be useful to augment other systems.
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Tidal current
Tidal current generation technologies would appear to be the most mature marine energy generation possibility for Stewart Island. The best prospects for economic utilisation of the resource is generally considered to be in water depths greater than 30 metres and mean spring peak velocities of greater than 2.5 ms-1. Smaller scale units appear to require greater currents: Blue Energy advise that a current of some 6 to 8 knots (3 to 4 ms-1) is required for their 250 kW generator.
The capacity factor of plants is estimated at 40% and costs are in the order of $6,000 to $9,000/kW for a small plant of 1 MW or less. Projected annual O&M costs are $150 per kW of installed capacityxv. A 200 kW generator can thus be expected to cost in the order of $1.2m to $1.8m resulting in generation at around 10.7 c/kWhr for a 20 year life. A 500 kW generator will thus cost in the order of $3.6m with an annual operating cost of around $75,000.
Local knowledge suggests that Ackers Point and Mamaku Point to be the most likely locations for tidal generators in the vicinity of Oban. Preliminary NIWA modelling xvi indicates that the maximum spring flows for these places to be in the order of 1 ms-1 (See Figure 5). While localised anomalies are possible it is considered very doubtful that there could be sufficient acceleration to provide 3 ms-1, or more, currents.
An approximate measurement of the tides experienced at these points has been obtained from small boats with GPS: drifts of up to 3 knots (1.5 ms-1) have recorded at Mamaku Point xvii . Actual current measurements recorded in the middle of Foveaux Straight by NIWA show peak velocities of 0.8 ms-1 and an average peak velocity of around 0.4 ms-1. These values closely match the NIWA predictions.
Because the NIWA model matches observed results so well, one can be confident that the tidal current velocities around Stewart Island are insufficient for tidal energy to be viable.
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Figure 5. Modelled peak spring tide velocities in knots (after Chiswell, 2007).
Tide
Tides around Stewart Island are not large and on average are 2.5 metres. The average tidal power head available is thus limited to between 0.5 and 1 metre. To store enough water to allow for 100 kW average power production will require at least an area 1 kilometre square and an average penstock flow of over 10 m3s-1. This is not very practicable.
Work undertaken by SDC in the 1980‟s indicate that the only areas that could be used for tidal power would not be environmentally tenable. Any tidal generation would result in such massive disturbance to the foreshore and seabed that it would not be permitted under the Coastal Plan and at any rate would unlikely receive any public support.
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Wave
Research carried out by NIWA shows that the wave heights in and around Oban are insufficient to be useful wave power generation. Even in Foveaux Straight, mean wave heights are only of the order of a few metres. Wave power is not a viable option given the currently available technology.
5.5. Undersea cable
The easiest source of renewable energy could be from the South Island, via an undersea cable. This option was examined in the past and is reviewed in light of developments in high voltage transmission. The required cable length is in the order of 40 km. Allowing for three-phase transmission at 33 kV, 20 mm2 three core cable would be necessary to keep losses to an acceptable level. General Cable XLPE 3C submersible cable at $100 per metrexviii provides a starting cost of $4 million. Laying costs, jointing and anchors could be expected to be another $4 million (the cost of laying a “smallish” cable across Cook Straight is in the order of $5M to $10M, excluding the purchase cost of the cablexix). As no New Zealand cable manufacturer would be capable of manufacturing this type of cable in the lengths required, any cable would have to come from off-shore. Lead times for such a project could well extend into many months.
Transformers at each end would increase the cost. More likely, transmission of ac current through 40 km of cable is too lossy and dc conversion will be required. Suitable inverters, such as the Xantrex GT500E 500 kW grid-tie inverters are now becoming generally available with the growth in large scale photovoltaic installations. A budget cost of around $1 million should be allowed to provide for the inverters and associated accommodation.
Up until 1980, New Zealand Post Office used a marine cable to provide telecommunications to Stewart Island. Anecdotal evidence suggests it suffered from outages from oyster dredging, anchor snags and other causes. Considerable effort would be required to prevent a reoccurrence of this situation. To this end the cable would most likely need to be trenched, or “jetted” in the seabed to withstand dredging operations. With the likely oil exploration work in the Deep South Basin about to begin, ships able to lay submarine cable should be easily available from mid to late 2008.
Indicative costs to install undersea cable are set out in Table 4.
Item Cost Cable $4m Laying, anchors, joints $4m Inverters $1m Total $9m Table 4. Indicative undersea cable costs
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5.6. Diesel generators
The present generators consume between 37,000 and 42,000 litres of diesel each month with efficiencies ranging between 3.09 kWhr / litre and 4.2 kWhr / litrexx. In 2006 the cost of diesel alone was estimated to be 30c / kWhr. Oil changes are required at 250 hours (10 days continuous running) and other maintenance is required at regular intervals. The regular maintenance is carried out by the manufacturers‟ agents.
If it is assumed that the cost of staffing and operating any generation system on Stewart Island will be a comparable overhead, then the predominant cost of generation is fuel. Fuel costs are currently in the order of $480,000 per year. In addition, around 5% of this total should be allowed in addition for consumables.
Over the life of this study, diesel oil prices are predicted to fall a little as new world-wide production comes on line, and then starting to rise after 2015 as demand again outstrips supply. By 2030 diesel is expect to be around 5% cheaper than in 2007 in real termsxxi. This means that over the life of the current generators, the price of diesel can be regarded as fixed.
It is possible for the diesel generators to be partly converted to use waste oil from motor vehicles on Stewart Island and boats. Given the substantial volume of diesel consumed each month and the small number of vehicles, there is a significant problem of scale which suggests that real savings would be limited.
It may be practical to produce bio-diesel on Stewart Island, utilising wild algae harvested from a modified sewerage scheme. This would have the potential to provide an alternative, „green‟ fuel source for the generators that may be cost effective. Aquaflow Bionomic Corporation xxii , based in Nelson, are actively working in this area and anticipate that their design assumptions will be validated in the next 12 months. Developments in this area should be followed closely.
The major problem with running diesel generators lies in that they are primarily designed to operate with a typical load factor of 60 to 70% of the prime rating with a peak demand of 100% for no more than 10% of the operating hours. Some skill is required in operating a bank of generators to optimise their performance, matching the generators in operation to the load presented.
A bare replacement 300 kWe genset engine has been priced at over $68,000 and installed replacement generators cost in the order of $90,000. The net present value of the diesel consumption over 20 years at a 10% discount rate and assuming that the price of diesel remains constant is $4.3 million. Over this period at least three generator sets will need to be replaced, which brings the net present value to $4.7 million.
The Southland Regional Energy Assessmentxxiii concluded that diesel generation was presently the most economic option for electricity production on Stewart Island.
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6. Energy storage
Should renewable energy supplies be adopted on Stewart Island, their success will be intrinsically linked to the ability to store surplus energy for subsequent use. In addition, any renewable system is going to provide uncertain instantaneous capacity; as the renewable supply will be the dominant generation source to be economically viable, maintaining grid stability thus becomes difficult. It is imperative that a successful energy storage and grid stability system is properly integrated to allow for renewable energy sources to be utilised.
The same energy storage systems for use with renewable energy sources can also be used with the current diesel engine-alternators for load levelling to provide improved operating efficiencies and late at night to supply electricity without the need to run the engine-alternators. Further, it is feasible to test, prove and commission any energy storage system independently of a renewable energy system, if implemented. This would allow for fine-tuning of such storage before it became “mission critical”.
Short term grid stability can, to some extent, be dealt with electronically, but some sort of bulk energy storage is also required. The storage options that are most likely to be applicable to Stewart Island and which are available or anywhere near being commercially available are now discussed.
6.1. Lead acid battery
Lead acid batteries are widely available and comparatively well understood. They are not tolerant to neglect, or deep discharges, which considerably shorten their lives. The cells need regular monthly maintenance. The life of a lead acid battery is dependent on the depth of discharge and the number of discharges, which is not straightforward to evaluate. Generally, deep cycle batteries can be considered to have a life of between 8 and 12 years.
The batteries can be installed either as a single battery bank, or distributed throughout the network, perhaps integrated into domestic solar photovoltaic generation systems as 16 kWhr, or so, battery banks.
Typically, deep cycle lead acid batteries cost in the order of $240 per rated kilowatt-hour of storage, but because discharging a battery to below 50% of its rated capacity will markedly shorten its life, in real terms the cost is close to $480 per realisable kilowatt- hour. A 500 kWhr battery will thus cost in the order of $240,000.
Rectifiers and inverters can be expected to cost in the order of $2,000 per kW, i.e. a 100 kW rectifier/inverter would cost around $200,000. This would be true for both single and distributed installations. Including rectifier/inverters brings the total capital cost of a 500 kWhr battery with connection to the network at 100 kW to around $440,000 plus gst, or over twenty years with one change of batteries, $680,000.
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6.2. Edison nickel-iron battery
Edison nickel-iron batteries can be considered to perform much like lead acid batteries, except that they are virtually indestructible, with lives of about 40 years that are essentially unrelated to use. They are very tolerant to abuse. However, they have a low energy storage density and are no longer manufactured outside of China. The low power density is not a disadvantage for Stewart Island as there is sufficient room at the present diesel generation site for them. The rated storage of an Edison nickel iron battery is close to the realisable storage as the cells can be completely discharged.
Prices sourced from the Internet indicate a cost of around $600/kWhr through the USA. This makes them comparable to lead acid batteries when operating costs are included in the short term and definitely more attractive over the long term. Cheaper prices should be possible by buying directly from China. Assuming a twenty year life for the batteries, the net cost of a 500 kWhr battery and inverters is $500,000.
6.3. Pumped hydro storage
Pumping water up to a storage lake for subsequent hydro power generation has been used in Europe for many years. The technology is simple, well understood and moderately easy to implement. The highest head able to be achieved at Stewart Island is 100 metres, which would require pumping from sea level to the hill adjacent to the airstrip at Ryans Creek. Marked improvements in efficiency can be achieved with higher heads, preferably 300 metres, but there is nowhere near, nor accessible that can provide such heads.
A Pelton Wheel turbine is most suited to such heads and has the added advantage of being very responsive to changing loads with both governing and vane-deflection techniques. This allows for rapid adaptation to changing grid power demand and renewable power generation fluctuations, assisting with grid stability.
Either sea water, or fresh water can be used for storage. Although fresh water could be expected to be less corrosive to plant, it would require a low as well as a high storage reservoir. Storage reservoirs will need to be around 20,000 m3 each. Each reservoir could consist of a sizable, geo-textile lined pond of, say, 100 m by 60 m by 4 m deep. Establishing such a reservoir would not be trivial on Stewart Island where there is no worthwhile bedrock, the soil types are variable and the roads are very light.
Canyon Hydro (Washington State, USA) estimate that for a 110 metre static head, a flow rate of 240 ls-1 will be required to develop an output of 200 kW, based on a nominal 240 m long, 14” diameter penstock. Their budget estimate for a suitable Pelton Wheel turbine coupled to a 3-phase, 400 V 50 Hz 600 rpm synchronous generator complete with governor, controls and switchgear is $US340,000 ($NZ460,000).
Hydroworks of Christchurch estimate that a pumped hydro scheme could be established as set out in Table 5.
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Item Cost ($NZ) Turbine $280,000 Generator $80,000 Controls $140,000 Pumps and fittings $120,000 Pump motors $70,000 Penstock, 500mm GRP $300,000 Total materials $990,000 Civil works $600,000 Consultancy fees $150,000 Contingency @ 20% $348,000 Total $2,088,000 Table 5. Pumped hydro budget
It should be noted that the civil works estimate is likely to be very much understated for the reservoir. A recent dam of a similar nature in Lumsden cost $300,000 for the physical works and with consents and engineering design the total came close to $500,000xxiv. Using a rule of thumb for works on Stewart Island, at least twice this amount would need to be budgeted, bringing the reservoir cost up to $1m and the hydro scheme to around $2.8m.
6.4. Hydrogen storage
Hydrogen storage technologies
Hydrogen storage technologies are currently limited to: compressed hydrogen gas, liquid hydrogen, complex hydrides, chemical hydrides and hydrogen adsorbents. Considerable effort is going on world-wide to commercialise these technologies for the automobile industry, which is likely to remain the prime driver for technological advances. With a typical car engine output rated between 50 kWmechanical and 130 kWmechanical, this scale of technology is likely to be appropriate for Stewart Island.
Estimated costs for car sized storage systems (around 600 kWhr, based on 0.2 kWhrmechanical/km, or 1 kWhr/kmfuel) are set out in Table 6.
Technology Capital cost ($NZ) Compressed hydrogen $7,000 - $10,000 Complex hydrides $4,000 - $6,000 Liquid hydrogen $3,000 - $6,000 Chemical hydrides $2,000 - $3,000 2010 target $1,400 2015 target $800 Table 6. Estimated costs of 600 kWhr hydrogen storage (after Satyapal, Petrovic & Thomas, 2007).
What is quite clear from this table is that the enormous research being spent in this area could result in affordable storage in the next 10 years. However, the costs are currently still very high. It should be noted that because cost figures are commercially sensitive
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and the market for hydrogen technologies is so restricted, the costs for one-off purchases of equipment vary greatly at the discretion of the technology suppliers. Significant cost reductions, or assistance in the design, development and implementation phases through vendor partnerships are possible.
However, at this stage only compressed hydrogen and liquid hydrogen are available, with the hydride batteries being in development and hydrogen adsorbent still in the R&D stagexxv. Of the commercially available technologies, liquid hydrogen is not an option for energy storage applications because of the additional energy requirements and capital costs for liquefaction, the cost of storage vessels and the problem of evaporative (or boil- off) losses over extended storage periods.
Compressed gaseous storage could be sized after the tube-trailer systems used for truck delivery in the industrial gas sector (See Figure 6). Operating pressures for these systems are normally between 15 and 23 MPa for a storage capacity of 100 to 300 kg of hydrogen, i.e. 3 to 10 MWh of stored energy. For Stewart Island, assuming a 40% efficient diesel generator running on hydrogen, this means having the capabilities to provide between 3 and 10 hours of supply.
Cost figures for commercially available compressed hydrogen storage vary greatly in the literature, but $US1500-1800 /kg of hydrogen is a reasonable estimate for one-off purchases of compressed hydrogen storage. One supplier is currently able to provide hydride storage for around $US3,000/kgxxvi.
Figure 6. An example of a hydrogen tube-trailer
There is considerable interest in hydrogen storage research in New Zealand and in particular by the groups lead by Dr Attilio Pigneri of the Centre for Energy Research at Massey University (MUCER) and Dr Alistair Gardner of IRL, Christchurch. Both groups are seeking to further develop their small scale research projects and so work on a larger project such as Stewart Island is appealing to them. Their research work would also be able to attract FoRST and suchlike funding.
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Electrolyser
The size of the electrolyser, which converts water to hydrogen, will depend primarily on the "off-peak" electricity available and the required storage capacity. The expected duration and power levels when running the system from the storage also influences the size. This will require some detailed system modelling starting from load profiles and wind resource availability. Costs for electrolysers are in the order of $US300/kW, i.e. around $NZ50,000 for a 100 kW unit.
Hydrogen utilisation
Two techniques are currently applicable to extract electrical energy from the stored hydrogen: hydrogen fuel cell, or to convert an existing diesel generator to run on hydrogen gas. The most expedient way forward for Stewart Island would be to adopt the latter. This would be implemented by establishing an electrolysis and storage facility at the present generator site.
Converting diesel engines to run on hydrogen is receiving increased attention given the current prices and level of development of fuel-cell technologies and the specific requirements for remote area applications. Many groups are working on diesel generator set conversions. One such group is a partnership between the University and Hydro Tasmania working on a project for Cape Barren Island, off the north-eastern cost of Tasmania. This diesel conversion is now operational and the partnership is now looking for new applications and research projects.
Some caution is, however, urged: hydrogen used in this manner is still under development and there may well exist as yet unforeseen problems in commercial deployment. Perhaps the greatest threat to viability arises from the high temperature at which hydrogen burns: it is sufficiently high that atmospheric nitrogen as well as oxygen will react with the hydrogen, producing nitrides that could corrode the engine.
Summary
The most likely way forward to use hydrogen as a storage medium for Stewart Island is to use surplus electrical energy to convert water to hydrogen with a standard electrolyser. Compressed gaseous hydrogen would then be stored until required, when it would be used to power a converted diesel generator set.
Indicative costs to establish a 400 kWhr hydrogen storage facility are set out in Table 7.
Technology Capital cost ($NZ) Electrolyser (200 kW) $50,000 Hydrogen storage, (15 kg compressed gas) $40,000 Diesel generator conversion $20,000 Grid connection equipment and accessories $300,000 Total $410,000 Table 7. Indicative prices to establish a 400 kWhr hydrogen storage facility (after Pigneri)
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6.5. Vanadium redox
Vanadium redox batteries are now commercially available and are in use in a number of places, including King Island, Australia. The chemical process is straightforward and only requires a pump to keep operational. Vanadium oxide is a by-product of the Glenbrook steel mill. Cells are available in 5 kW and 50 kW stacks. A round trip efficiency of 75% can be expected. A lifetime of 15 years should be planned for the conversion cells. The battery could be established at Hicks Road adjacent to the present generators.
Indicative costs for VRB vanadium redox batteries are set out in Table 8. The prices include grid connection equipment.
Technology Capital cost ($NZ) 200 kW cell with 2,000 kWhr storage $2M 400 kW cell with 2,000 kWhr storage $3M Electrolyte, per kWhr of additional storage $120 Table 8. Redox battery prices (after EmPower Consultants)
6.6. Zinc-bromine batteries
Zinc-bromine batteries are a flowing electrolyte battery, currently being developed in Australiaxxvii. The technology provides energy densities of 2 to 3 times greater than for lead acid batteries and have much superior deep discharge characteristics. The nature of the electrolyte means that it should be possible to realise cheaper capital costs. The technology is becoming commercial with some demonstration plants running. ZBB Energy Corporation ship a 500 kWhr battery system, complete with inverter and ready to run for $US402,000 FOB Milwaukee. This equates to a landed price in the order of $700,000. Additional 50 kWhr battery modules can be added at $US25,000 each.
Technology Capital cost ($NZ) 500 kWhr battery $400,000 Grid connection equipment and accessories $300,000 Total $700,000 Table 9. Quoted prices for Zinc-bromine batteries (after ZBB Energy Corporation)
6.7. Diesel
The present diesel generators offer the most reliable source of stored energy. If they are only used for topping up renewable generators, the present line-up of generator sets could last for the foreseeable future.
Diesels require to be run at around 70% to 80% of their rated capacity in order to prevent glazing of the cylinder bores and to achieve reasonable operating efficiencies. They also require some minutes to warm up before generating. For this reason they are not suitable for instantaneous grid stability applications and would most likely need to be
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used with electronic storage of some sort if used to supplement wind, or solar generators.
One, or more of the diesel generator sets could be converted to run on hydrogen, as outlined earlier. Given that this approach is relatively new, considerable care would be needed to ensure that the engines are able to be used in this manner without long term deterioration. Alternatively, there is the possibility of adapting the Oban sewerage oxidation ponds to produce algae that in turn could be harvested to produce bio-diesel. At this stage, no commercially available bio-diesel production equipment utilising this source is known and indicative costs and production rates are not yet available. Work in this area by Aquaflow Bionomic Corporation looks promising and if all goes well, commercial plant may be available in the near to medium future. The existing diesel generators would likely need little, or no modification to use bio-diesel.
Regardless, it would be sensible to retain the diesel engine-alternators for medium term power peak assistance, replacement generation should a renewable generator fail and in case of sustained absence of renewable energy sources, such as prolonged calm periods for wind turbines.
6.8. Other storage technologies
A number of other technologies were investigated, but were insufficiently developed to be seriously considered for Stewart Island. Some of the better know technologies are discussed below for completeness.
Carbon block
Carbon block batteries are still in early commercialisation stages. Hydro Tasmania are evaluating this technology at King Island at present. They suffer from the disadvantage of requiring high temperatures. The technology is not yet commercial.
Compressed air energy storage
Compressed air energy storage (CAES) is considered to be one of the more proven energy storage systems. Air is pumped into an underground cavern, slowly heated and then later re-used though a standard gas turbine. Small scale reservoir systems of around 1 MWhr capacity can be built out of buried steel pipe. To give an idea of scale, the storage for such a system would consist of 250 metres of 1 metre diameter steel pipes, with an operating temperature of 270 ˚C. Indicative pricesxxviii are set out in Table 10.
Technology Capital cost ($NZ) Compressor and motor $800,000 Storage pipe $350,000 Civil works $200,000 Rectifiers and inverters $300,000 Total $1,650,000 Table 10. Indicative prices for compressed air energy storage
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While these prices compare favourably with other technologies, to use this system would require establishing a gas turbine at Stewart Island. Unless other requirements are found to justify a gas turbine, this is not a viable option.
6.9. Summary of storage options
The comparative costs of the available energy storage options are set out in Table 11.
Technology Capital cost ($NZ) Hydrogen, compressed gas $410,000 Edison nickel-iron cells, 500 kWhr $500,000 Lead acid secondary cells, 500 kWhr $680,000 Zinc-bromine cells, 500 kWhr $700,000 Compressed air energy storage $1,650,000 Pumped hydro storage, 600 kWhr $2,800,000 Vanadium redox, 400 kWhr $3,000,000 Table 11. Indicative prices for energy storage and grid connection
7. Summary of generation and storage options
Estimated costs to establish and operate generating facilities on Stewart Island are set out in Table 12. The table assumes replacement of the generators at the end of their economic lives with equivalent technology. The key economic assumptions are that energy consumption grows at 1% per year (a full demand side analysis is required to refine this assumption) and that the costs of technology and fuel will not change differently to inflation. A more detailed net present value calculation for diesel, wind and wind storage options is contained in Appendix VII.
Technology Generator Storage OPEX NPV Total NPV CAPEX CAPEX (10%, 20 yrs) (10%, 20 yrs) Wind, Hydrogen $1,500,000 $400,000 $200,000 $2,200,000 Wind, Ni-Fe cells $1,500,000 $500,000 $200,000 $2,300,000 Wind, diesel storage $1,500,000 - $1,900,000 $3,400,000 Diesel $160,000 - $4,50,000 $4,660,000 Solar PV, Hydrogen $5,000,000 $400,000 $50,000 $5,450,000 Marine tidal current* $4,500,000 $500,000 $600,000 $5,600,000 Undersea cable $6,000,000 - - $9,000,000 Hydro* $25,000,000 - - $25,000,000 Table 12. Net Present Values of technology options (Technologies marked with an * are not practicable and are shown for completeness only)
From analysis of Table 12 it is clear that there is a strong case for wind power on Stewart Island in the long term. There is little difference between the better energy storage options for wind generators and further, detailed analysis is required to confirm the best option. This will only be possible once the results of more detailed wind studies become available. It should be noted that, based on United States official predictions, the price of diesel in this analysis has assumed to be less than that of inflationxxix.
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The wind generation and storage costs are roughly half that of continuing to use the generators. This would imply that by adopting these technologies the direct cost of generation could correspondently be halved. Due to the significant overheads in running SIESA, this would not necessarily result in a halving of the price of electricity.
Further detailed investigation and costing of wind generation coupled with gaseous hydrogen storage and Edison nickel-iron cells is now required to confirm the best solution.
8. Demand side management
The usage of electricity has two components that need to be addressed: peak loading and overall daily electrical energy consumption. The former sets the generation, or generation and reserve capacity, while the latter sets the overall energy budget and – directly or indirectly – the amount of fossil fuel consumed.
Aside from the major ten electricity users on Stewart Island, which include the Southland District Council utilities, nearly all other electricity use is believed to be for domestic purposes. While further research is required to confirm how the domestic use of electricity in Stewart Island compares to other parts of New Zealand, it is nonetheless instructive to use the average New Zealand consumption for a guide.
To a first approximation, the average house in New Zealand consumes electrical energy as set out in Table 13. By using energy efficient design, the space heating can be reduced to 2,000 kWhr/year and by using energy efficient heating, such as heat pumps, this can be reduced to 800 kWhr/year. Solar hot water heating, or heat pump heating of domestic hot water can reduce the hot water heating requirement to 1,500 kWhr/year. Energy efficient lights can reduce the lighting consumption to 150 kWhr/year and using energy efficient refrigerators and other appliances can reduce the refrigeration requirement to 300 kWhr/year. By adopting intensive energy efficient building designs and using energy efficient equipment, the electricity consumption can be reduced by two thirds. By using solid fuel for space heating, the total electricity consumption can be reduced to around 1,000 kWhr/year.
Use Average household Efficient household (kWhr/year) (kWhr/year) Space heating 4,000 800 Hot water heating 4,000 1,500 Lighting 600 150 Refrigeration 800 300 Other 600 600 Total 10,000 3,350 Table 13. Annual domestic electricity consumption for an average and energy efficient households (after A G Williamson)
These values may be realisable on new homes being built in Oban, but most existing homes were built when abundant electricity was not available. Accordingly, many homes use wood, coal and diesel for space heating. Coal on Stewart Island currently costs $400 per tonne and diesel costs $1.30 per litre. Although some 30% more expensive
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than in Invercargill, coal on Stewart Island is able to deliver heat at around $0.20/kWhr under favourable conditions1. Anecdotal evidence suggests that many consumers would be amenable to using electricity instead of solid heating fuels if they were cheaper.
Without undertaking surveys of existing houses, it is not clear to what extent electrical energy use can be reduced. However, a rough estimate can be deduced knowing from Appendix II that the top ten consumers take 50% of the generated electricity: some 430 consumers are thus responsible for purchasing the remaining half, which for 2006/7 was 881,835 kWhr, i.e 2,000 kWhr per household. This suggests that most consumers are presently using alternative energy sources to electricity for space and water heating. However, it should be noted that this calculation disregards that a number of dwellings are only occupied for part of the year and so permanent households will likely have a higher consumption.
Before implementing improved space heating systems, for example, it is important that existing domestic dwellings and commercial premises consider improving the thermal efficiency of the buildings. Areas to address include moisture vapour barriers, under-floor and ceiling insulation, hot water cylinder wraps, double and triple glazing, and draft- stopping windows. For an average home on Stewart Island, the cost of retrofitting these measures will typically be between $2,400 and $3,000. In addition, research confirms that living conditions and the health of the occupants would be significantly improved. The Bluff Healthy Homes Projectxxx provides a model that could be adopted and it is recommended that such a scheme be considered for adoption at Oban.
9. Proposed course of action
There are two areas to investigate: the demand side, or consumer use and the supply side, or production.
9.1. Demand side analysis and management
There are only a few hundred electricity consumers on Stewart Island. A Pareto analysis of consumers, whereby customers are ranked by consumption is required to identify high-use domestic consumers and assist them to find ways to spread their electrical load and/or reduce their consumption. The top ten consumers have already been identified.
SDC is currently analysing their overall electricity usage, including that at Stewart Island. Some 15 pumps on Stewart Island have so far been identified as being worthy of closer attention and possible replacement with more energy efficient pumps. SDC is also investigating the feasibility of converting the mode of operation of some of the larger pumps in order to spread the load and reduce peak loading. Energy efficient street lighting should also be examined.
1 To a first approximation, coal has a calorific value of 20 MJkg-1. At $400/tonne, coal is thus able to provide heat at $0.072/kWhr at 100% utilisation. Optimistically, an open fire has a heating efficiency of 5%, equating to $1.44/kWhrdelivered, while a high performance multi-burner could achieve up to 35% heating efficiency, equating to $0.21/kWhrdelivered. For comparison, a heatpump with a COP of 3.0 at Stewart Island would run at $0.17/kWhrdelivered.
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Anecdotally, many residential consumers are reported to have already looked at reducing electrical demand through adoption of energy efficient lighting, wood-fire space heating and so on. Presumably with the passage of time, it will become increasingly difficult to secure continued wood supplies within the Oban area. It is not known how widespread such electricity substitution measures are and so it would be worthwhile to survey all consumers to this end. Given the low number of consumers, a sampling survey is not warranted.
What is not clear is how future annual and diurnal peak loads will be driven as the demographics of Oban change, arising from new subdivisions, offshore investment in holiday cribs and so on. Work is needed to characterise future growth in electricity demand. This demand also will hinge upon the alternative generation prices and this needs to be analysed also.
A second level of demand side investigation is likely to be required when replacement, or augmented electricity supplies are being evaluated: it may be more economic for SDC to encourage more efficient heating and lighting than increase capacity on the supply side. Equally, it may behove SDC to incorporate requirements for energy efficiency and electrical energy substitution in all new buildings in the District Plan, which is due for review later this year.
An active programme to upgrade all existing dwellings on Stewart Island for optimum energy efficiency should also be further investigated, perhaps using the Bluff Warm Homes project as a model.
The Energy and Technical Services response to the RFP contained the most comprehensive demand side study methodology, using a survey questionnaire, telephone survey and face-to-face questionnaire. The survey would be managed by Dr Susan Krumdieck of the Mechanical Engineering Department, University of Canterbury and using SIT interviewers. The costs to carry out this research is set out in Table 14. It may be possible to reduce the costs by using a masters student and applying for a MoRST grant to subsidise the student.
Activity Price (excl gst) Develop survey questionnaire $3,400 Undertake interviews $3,800 Analyse data and prepare report $21,200 Total $28,400 Table 14. Demand side research prices, ET&S.
9.2. Wind data collection and modelling
Of all the alternative energy supplies, by far the strongest contender is wind power. It is thus imperative to begin collecting reliable wind flow data as soon as possible. The options are available:
Empower Consultants are able to supply wind sensors:
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Full set of datalogger and wind speed and direction sensors $90 / month One 30 metre tower set $150 / month Total $240 / month
Over a twelve months monitoring period, data collection will cost $2,880 plus gst per site plus installation. With installation, $5,500 per site for one year of data collection should be allowed for.
Alternatively, Empower Consultants can supply a 30 meter tower set for $5,500 plus gst plus freight for SIESA to own and operate.
Windflow are prepared to run a 3 month trial on a site for $5,000 plus gst. The advantage of using Windflow is that they would provide a turn-key solution and have considerable experience in selecting optimal sites to erect measuring equipment.
The most promising sites to measure wind runs are:
Ackers Point Ryans Creek / airport Deep Bay (Scofield property) Garden Mound 9.3. Grid stability and energy storage modelling and trial
It is proposed that before trailing any renewable energy source, the predicted grid stability should be thoroughly analysed. Dr Alan Wood of the University of Canterbury School of Engineering has the requisite expertise in modelling power networks. He advises that he could supervise a post-graduate student to work on the project, which would then be eligible for FRST fundings.
To carry out the modelling, a full set of plans for the network are required along with electricity demand and time of day data for any renewable energy source.
The cost of carrying out a grid stability study is $16,000, half of which should be able to be funded from an FRST grant if a post-graduate student is involved.
10. Activities
The following activities and timetable is suggested in Table 15.
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Activity Lead agency Contractor Budget (exl GST)
Immediately Identify sewer and water pumping SDC SDC nil optimisation Seek funding to evaluate and trial bulk VS IRL / - energy storage on Stewart Island MUCER Undertake analysis of current consumers SIESA SDC $2,000 SIESA Univ of $10,000 Canty
Short term Undertake demand side study forecasting VS Univ of $28,400 future demand; commercial sensitivity to Canty tariffs, and risk assessment and mitigation; scope for improved domestic dwelling upgrades. Trial solar electricity generation DOC tbc $60,000 Bid for trial tidal current generator under VS tbc - MED “Marine Energy Deployment Fund” Tender for bulk energy storage trial VS IRL / $5,000 MUCER Undertake wind data collection VS Windflow $10,000 Undertake grid stability modelling VS Univ of $16,000 Canty Project Management VS $20,000 Total $151,400 Table 15. Proposed actions
11. Budget and funding
A proposed budget to carry out the activities in Table 15 is set out in Table 16.
Activity (Funder) SDC Other Total cost contribution contribution Wind monitoring at two sites (EECA) $5,000 $5,000 $10,000 Grid stability study (FRST) $8,000 $8,000 $16,000 Demand side analysis (EECA) $28,400 $28,400 Trial solar electricity generation (DoC) $60,000 $60,000 Venture Southland management $20,000 $20,000 Funding shortfall $17,000 $17,000 Total $13,000 $138,400 $151,400 Table 16. Proposed activity budget
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12. Acknowledgements
I wish to thank the following people for their assistance in preparing this report:
Brett Bauer, Canyon Hydro Dr Steve Chiswell, NIWA Robert Deller, Transpower Chris Dillon, Power Line Services Bruce Forde, Stewart Island Community Board Dr Alister Gardiner, IRL Rik Hothersall, Hydroworks Sheralee McDonald, Windflow Technology Assoc. Prof. Attilio Pigneri, Massey University Centre for Energy Research Andy Roberts, Department of Conservation Jim Tait, General Cable Peter Thompson, SDC and SIESA Yvette Waymouth, SDC Robin Webb Nick Williamson, Thermocell Prof. Arthur Williamson, University of Canterbury Dr Allan Wood, University of Canterbury Tony Woods, Empower Consultants
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Appendix I. Location and land status maps
Topographical map of Oban and environs
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Oban land status (after Department of Conservation)
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Appendix II. Electricity demand
Monthly electrical energy generation
Year Demand (kWhr) Peak month Minimum month Annual 92/93 103,941 71,286 992,132 93/94 111,290 74,155 1,040,272 94/95 116,221 80,767 1,113,266 95/96 122,183 82,766 1,137,642 96/97 124,671 92,954 1,289,586 97/98 128,290 86,958 1,334,009 98/99 128,947 110,772 1,388,413 99/00 156,692 109,223 1,471,981 2006/07 165,120 134,135 1,763,670 Monthly electrical energy generation 1992 – 2000 (after SDCxxxi) and 2006/7
170000
160000
150000
140000
130000
Generation (kWhr) Generation 120000
110000
100000 Sep- Oct- Dec- Feb- Mar- May- Jul-06 Aug- Oct- Nov- Jan- Mar- Apr- 05 05 05 06 06 06 06 06 06 07 07 07
Monthly electrical energy generation 2005 – 2007 (after SIESAxxxii)
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Typical daily generation
Generation 1/6/06
350
300
250
200 Max (kw) Min (kW)
150 Avg (kW) Generation (kW) Generation 100
50
0 Time of day
Typical generation for winter, off-season, 8am -7:30am
Generation 17 April 2006
500 450 400 350 300 Max (kw) 250 Min (kW) 200 Avg (kW)
Generation (kW) Generation 150 100 50 0 ......
Time of day
Typical generation for autumn, high-season, 8am -7:30am
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60%
50%
40%
30%
20% Consumption (%)
10%
0% 0 1 2 3 4 5 6 7 8 9 10 Customer
Top ten SIESA customers for May 2007 by consumption.
Appendix III. Regulations pertaining to SIESA
The Southland District Council is obliged to supply electricity in compliance with the Electricity Act 1992 and the Electricity Regulations 1997. The SDC operates in terms of the legislation as an “electricity operator”. In terms of the 1987 licence currently held by the SDC, the “systems of supply” were to be as provided under Regulation 13(a), (b), (c), (d), (e), (f) and (g) Electrical Supply Regulations 1984.
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Appendix IV. Network diagram
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Appendix V. Storage dimensioning and costs
The following table and chart provide a comprehensive, if generalised resource to evaluate energy storage for renewable electricity supplies xxxiii . For Stewart Island, allowing for 10 hours storage, the following approximate values are can be used: power: 400 kW; energy 4,000 kWh.
FW, Flywheel; SMES, Superconducting Magnetic Energy Storage; FC, Fuel Cell; PH, Pumped Hydro; Bat, Lead acid battery; CAES Compressed air energy storage; Cap, Super capacitor.
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Appendix VI. Hydro power catchments
After E.R. Garden & Partners Ltd (1982)
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Appendix VII. Net Present Value calculations for diesel and wind generation
Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Discount rate 10.0% Discount factor 1.0000 0.9000 0.8100 0.7290 0.6561 0.5905 0.5314 0.4783 0.4305 0.3874 0.3487 0.3138 0.2824 0.2542 0.2288 0.2059 0.1853 0.1668 0.1501 0.1351 0.1216
Annual growth in consumption 1% Peak Demand (kW) 450 455 459 464 468 473 478 482 487 492 497 502 507 512 517 522 528 533 538 544 549 Annual generation (kWh) 1763670 1781307 1799120 1817111 1835282 1853635 1872171 1890893 1909802 1928900 1948189 1967671 1987348 2007221 2027293 2047566 2068042 2088722 2109609 2130706 2152013
Generation
Diesel Operating costs NPV Diesel price (c/gal) (after DOE/EIA) 270.4 249.9 237.5 230.4 219.3 210.9 208.5 203.1 203.6 207.2 206.6 207.7 212.1 211.2 212.2 216.1 212.0 214.3 218.1 217.0 219.6 Fuel price multiplier 1.00 0.92 0.88 0.85 0.81 0.78 0.77 0.75 0.75 0.77 0.76 0.77 0.78 0.78 0.79 0.80 0.78 0.79 0.81 0.80 0.81 Price ($/litre) $ 1.20 $ 1.11 $ 1.05 $ 1.02 $ 0.97 $ 0.94 $ 0.93 $ 0.90 $ 0.90 $ 0.92 $ 0.92 $ 0.92 $ 0.94 $ 0.94 $ 0.94 $ 0.96 $ 0.94 $ 0.95 $ 0.97 $ 0.96 $ 0.97 Generator efficiency (kWh/litre) 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 Fuel cost $ 542,668 $ 506,511 $ 486,219 $ 476,570 $ 457,979 $ 444,954 $ 444,171 $ 437,085 $ 442,583 $ 454,873 $ 458,038 $ 465,144 $ 479,758 $ 482,557 $ 489,687 $ 503,669 $ 498,983 $ 509,447 $ 523,518 $ 526,143 $ 537,842 NPV Fuel cost $ 4,286,880 $ 542,668 $ 455,860 $ 393,837 $ 347,419 $ 300,480 $ 262,741 $ 236,051 $ 209,057 $ 190,517 $ 176,227 $ 159,708 $ 145,967 $ 135,498 $ 122,660 $ 112,025 $ 103,701 $ 92,463 $ 84,961 $ 78,577 $ 71,074 $ 65,389 Consumerables 5% $ 27,133 $ 25,326 $ 24,311 $ 23,828 $ 22,899 $ 22,248 $ 22,209 $ 21,854 $ 22,129 $ 22,744 $ 22,902 $ 23,257 $ 23,988 $ 24,128 $ 24,484 $ 25,183 $ 24,949 $ 25,472 $ 26,176 $ 26,307 $ 26,892 NPV Consumerables $ 214,344 $ 27,133 $ 22,793 $ 19,692 $ 17,371 $ 15,024 $ 13,137 $ 11,803 $ 10,453 $ 9,526 $ 8,811 $ 7,985 $ 7,298 $ 6,775 $ 6,133 $ 5,601 $ 5,185 $ 4,623 $ 4,248 $ 3,929 $ 3,554 $ 3,269
Capital expenditure Replacement gen sets $ 100,000 $ 100,000 $ 100,000 $ 100,000 NPV gen sets $ 156,375 $ 72,900 $ 43,047 $ 25,419 $ 15,009
Total $ 4,657,599
Wind Capital expenditure Wind turbine & controls $ 1,000,000 $ 1,000,000 Civil works $ 200,000 $ 200,000 Power line extension $ 300,000 $ 300,000
Operating costs 5% $ 50,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 NPV operating costs $ 168,587 $ 50,000 $ 13,500 $ 12,150 $ 10,935 $ 9,842 $ 8,857 $ 7,972 $ 7,174 $ 6,457 $ 5,811 $ 5,230 $ 4,707 $ 4,236 $ 3,813 $ 3,432 $ 3,088 $ 2,780 $ 2,502 $ 2,251 $ 2,026 $ 1,824 $ 1,668,587 Compressed Hydrogen Capital expenditure Electrolyser $ 50,000 $ 50,000 Storage and generator conversion $ 60,000 $ 60,000 Grid connection $ 300,000 $ 300,000
Operating costs 5% $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 $ 5,500 NPV operating costs $ 48,982 $ 5,500 $ 4,950 $ 4,455 $ 4,010 $ 3,609 $ 3,248 $ 2,923 $ 2,631 $ 2,368 $ 2,131 $ 1,918 $ 1,726 $ 1,553 $ 1,398 $ 1,258 $ 1,132 $ 1,019 $ 917 $ 826 $ 743 $ 669 $ 458,982 Wind with hydrogen storage $ 2,127,569
Wind with diesel backup Wind availability 60% Wind Capex and Opex $ 1,668,587 Diesel contribution $ 1,863,040 Total $ 3,531,627
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References i Southland District Council, Schedule of Council Fees and Charges, effective 1st July 2007. ii Venture Southland memorandum of 15 September 2006, Review of Electrical Power and Energy Options for Stewart Island: analysis of proposals. iii www.zerocarbon.co.nz iv Tourism Resource Consultants, Southland Tourism Strategy, 2005 – 2015, June 2005. v Department of Conservation Conservation Management Strategy: Stewart Island – Rakiura 1997 – 2007, December 1997. vi ER Garden & Partners; Royds Sutherland McLeay Hydro-electric potential and other energy resources, Stewart Island, 1982. vii NASA Surface meteorology and Solar Energy - Available tables at latitude -47 and longitude 168, http://eosweb.larc.nasa.gov viii www.indepower.co.nz ix ibid x ibid xi RETScreen® Clean Energy Project Analysis Software, http://www.retscreen.net. xii Prof. A G Williamson, pers comms. 5 April 2007. xiii IEA-OES Newsletter, Issue 7, September 2006. xiv Meridian Energy Information Sheet, Marine Energy, March 2007. xv Noel Hall, Chris Taylor, Emerging Supply-side Energy Technologies, Prepared for Min. of Economic Development, July 2006. xvi Dr Steve Chiswell, NIWA, pers comms, 20 March 2007. xvii Bruce Forde, pers comms, 16 May 2007. xviii Jim Tait, General Cable, pers. comms, May 2007 xix Robert Deller, Transpower, pers comms, 2 May 2007.
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xx SIESA Monthly Reports xxi DOE, Annual Energy Outlook 2007 with Projections to 2030, Report DOE/EIA-0383, 2007 www.eia.doe.gov/oiaf/aeo/index.html. xxii www.aquaflowgroup.com xxiii East Harbour Management Services Southland Regional Energy Assessment: Report to Venture Southland, November 2003. xxiv R Corlett, Opus Consulting, pers comms, 28 May 2007. xxv Sunita Satyapal, John Petrovid, George Thomas Gassing up with Hydrogen, in Scientific American, April 2007, pp 62-69. xxvi Attilio Pigneri, MUCER, pers coms, 21 June 2007. xxvii www.zbbenergy.com xxviii www.espcinc.com xxix ibid xxx www.healthyhomesproject.co.nz xxxi Southland District Council, Stewart Island Electrical Supply Authority [SIESA] Asset Management Plan 2000-2015, 1 June 2000. xxxii SIESA, Monthly Report, April 2007 xxxiii Schoenung, Susan M. Characteristics and Technologies for Long-vs. Short-Term Energy Storage, Sandia National Laboratories, for DOE Energy Storage Systems Program., March 2001.
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