UPEC2010 31st Aug - 3rd Sept 2010

Proposed Iceland/UK (Peterhead) 1.2 GW HVDC Cable

1 Thomas J. Hammons , University of Glasgow, United Kingdom. Email: T.Hammons@btinternet.com

Egill Benedikt Hreinsson, University of Iceland, Reykjavik, Iceland. Email: Egill@hi.is Piotr Kacejko, Lublin University of Technology, Poland. Email: P.Kacejko@pollub.pl

Abstract

This Paper presents and discusses the current situation of developments in harnessing hydropower in Iceland for large­scale generation of electricity for export by cable to the United Kingdom. It addresses (i) market considerations with cost of electricity from new offshore and inland wind power, gas and coal-fired plant, and nuclear plant, (ii) investments for the development of hydro resources in Iceland, (iii) submarine cables and converter plant, and (iv) overall capacity of the link.

It is noted that (a) there should be no major difficulties in the manufacture and laying of submarine cables of length and type necessary for the Link, (b) availability of the connection should be at least equal to that of new coal/gas and nuclear plant, and (c) cost of delivered energy would be very competitive with offshore and onshore wind, and of new coal/gas and nuclear plant.

Also reviewed is deep drilling projects in Iceland, the exploration of deep unconventional geothermal resources in NE Iceland that could be harnessed in future that could be developed in future for the link. The economics, availability, and reliability of geothermal plants are reviewed.

Keywords: Market considerations for HVDC Link; economics of Icelandic hydro power; hydro developments in Iceland; HVDC submarine cables; HVDC converter stations; power generation costs for Iceland/UK cable; geothermal power generation; drilling for geothermal energy; geothermal research and development.

1. Introduction

This paper discusses economically harnessable hydropower in Iceland for transmission to the UK and onwards as an energy source for reducing greenhouse gas emissions. It is an update of an earlier paper on Feasibility of Iceland/United Kingdom HVDC Submarine Cable Link published in 1989 [1], and others [2-5]. Advanced Geothermal Power Generation in Iceland that could be developed as a source of renewable energy for the UK and Europe in future is evaluated in Reference [6].

Other early proposals and studies include [7], and later studies and discussions primarily on a spot market based links include [8-10]. These have also reviewed the Iceland energy resources in this context to considerable detail.

Onshore and offshore wind-power is being developed extensively in the UK at this time and new high-efficiency gas/coal-fired plant is being commissioned. New nuclear plant is planned to replace the existing life-expired nuclear generation. Iceland is a huge energy opportunity as North Sea oil reserves are declining rapidly.

Iceland has huge untapped hydro potential. Iceland has a unique geographical location on the collision/edge of two huge tectonic plates: the European and the North American. This creates possibilities to harvest by deep drilling, when the

technology is proven, vast amounts of geothermal on the low height parts of the fault.

Iceland's total external debt is now between 400% and 900% of its GDP, depending on the reference. Up to half of that may be short term. As a result, the economy will decline rapidly if this is not addressed appropriately. The GDP/debt ratio will increase more if nothing is done. Energy for debt has therefore been proposed to benefit the Icelandic economy, rather than demanding huge amounts out of a heavily damaged economy without supporting necessary recovery. In this proposal, the interests of the debtor and of creditors merge into a common plan for the future.

This paper addresses the viability of a submarine cable connection from Iceland to Scotland to connect with the proposed EU HVDC cable hub at Peterhead in Scotland with onward connections to England, Netherlands, Europe and Scandinavia (see Ten year Network Development Plan, http://ensoe.eul). Hydro developments in Iceland, submarine cables, HVDC transmission, rectifier/inverter stations, investment cost attributable to a power sale, availability of the connection, technical considerations and cost comparisons for electricity from Iceland to the UK are examined.

It is noted the European Union hopes to generate a fifth of its electricity from renewable energies by 2020. This requires its member states to easily move electricity from one country to another. Late 2009, nine European countries agreed to build a power grid of HV cables under the North Sea. It will be the first multinational grid designed to address the fluctuation nature of green power generation. The grid will transport energy generated by a mix of wind, hydro, solar, and tidal power between Belgium, Denmark, France, Germany, Norway, and the United Kingdom to better balance supply and demand. Energy produced at night in UK wind farms, for example, could be stored in Norway's hydropower facilities and released the following day. The European power companies currently plan around 100 GWs of offshore wind power. The North Sea cable project, estimated to cost the nine countries more than 30 billion Euros, will be financed through a mix of taxpayers' money and private investment, largely from energy companies. The proposed 1.2 GW Iceland power cable would be linked in to the North Sea cable grid at Peterhead and would operate partly base load but could partly be operated as means of interaction between the UK/North Sea wind resources and Iceland hydroelectric reservoirs. Later developments could include the almost unlimited geothermal power from Iceland that could become available when the technology is proven. 2. Hydropower Sites in Iceland: Capacity, Energy,

Connection Cost and Energy in Cost Group

Investment costs are given in pounds sterling at January 2010 prices using the exchange rate that was applicable at the time. Some discrepancies will always be present because of rate of exchange fluctuations and different costs trends. Such

T J Hammons, DSc, CEng, FIEEE, International Practices for Energy Development and Power Generation, Glasgow University, llC Winton Drive, Glasgow G 12 OPZ, United Kingdom, Tel: +44-141-339-7770.

deviations are not believed to be of vital importance in assessing the overall viability of the development.

Table I shows technically harnessable hydropower for each hydro plant in Iceland. It indicates that the potential is roughly 3 GW and would produce about 22,400 GWh/yr. The

Table also indicates approximate connection costs and cost of energy in the six cost groups for which the cheapest is listed first. Where capacity in MW and utilisation time in h/yr is not indicated, the energy is on account of water diversions or increased storage capacity.

T bl 1 H d a e 1yl rop ower S't . I I eS In d C ce an : 't E ap aclly, ner gy, C f C t d E onnecl on os an . C t G nergy In os roup Table Project Name Reference Capacity Energy Utilisa Cost Connection In Phase Energy Item Number on (MW) (GWh/yr) -tion Group Cost

# One in Cost Figure 1 Time (£/kWh/yr) Group

(h/yr) (£m/GWh/yr) (GWh/yr)

1 Skaftarveita an miolunar i Langasj6 17 -- 465 -- I -- No

2 Tungnirrl6n 24 -- 270 -- I -- No

3 NorolingaOlduveita- 566-567,5 m y.s. 27 -- 635 -- I -- No 1370 4 Arnardalsvirkjun 12 570 4000 7018 2 0.00316 Yes

5 Skaftarveita meo miolun i Langasj6 16 -- 245 -- 2 -- Yes

6 Urrioafossvirkjun 31 130 980 7538 2 0.00210 Yes

7 Bulandsvirkjun 40 150 970 6467 2 0.00789 No 6195 8 Skatastaoavirkjun B 6 184 1260 6848 3 0.00653 Yes

9 Hrafnabjargavirkjun A 10 89 622 6989 3 0.00905 Yes

10 Skaftarvirkjun 18 125 760 6080 3 0.00937 Yes

11 H61msarvirkjun - an miolunar 19 72 450 6250 3 0.01968 Yes

12 H61msarvirkjun - miolun i H61msirrl6ni 20 72 470 6528 3 0.01684 No

13 H61msarvirkjun neori 21 48 360 7500 3 0.02200 No

14 Bjallavirkjun 25 46 340 7391 3 0.00711 No

15 BuoarMlsvirkjun 28 80 585 7313 3 0.00763 Yes

16 Selfossvirkjun 38 30 250 8333 3 0.00279 No 5097 17 Blonduveita 5 20 131 6550 4 0.01400 No

18 Skatastaoavirkjun C 7 156 1090 6987 4 0.00753 No

19 Villinganesvirkjun 8 33 237 7182 4 0.00795 Yes

20 Helmingsvirkjun 13 270 2100 7778 4 0.00126 No

21 Ojupa 14 75 498 6640 4 0.00626 No

22 Hverfistlj6t 15 40 260 6500 4 0.01411 No

23 Markartlj6tsvirkjun B 23 109 735 6743 4 0.01237 Yes

24 SkrokkOlduvirkjun 26 30 215 7167 4 0.05421 No

25 Hvammsvirkjun 29 82 665 8110 4 0.00363 Yes

26 Holtavirkjun 30 53 415 7830 4 0.00421 Yes

27 B1afellsvirkjun 33 76 536 7053 4 0.01395 Yes

28 Buoartunguvirkjun 34 50 320 6400 4 0.00989 No

29 Haukholtsvirkjun 35 60 358 5967 4 0.01000 No

30 Hestvatnsvirkjun 37 40 300 7500 4 0.00916 No 7860 31 Hvita i Borgarfiroi 1 20 125 6250 5 0.02905 No

32 Glamuvirkjun 2 67 400 5970 5 0.01089 No

33 Hvala 4 35 259 7400 5 0.02974 No

34 Eyjadalsarvirkjun 11 8 58 7250 5 0.02253 No

35 Markartlj6tsvirkjun A 22 14 120 8571 5 0.09394 Yes

36 Gygjarfossvirkjun 32 21 146 6952 5 0.11316 No

37 Hagavatnsvirkjun 39 20 140 7000 5 0.03232 No 1248 38 SkUfnavatnavirkjun 3 8.5 60 7059 6 0.09563 No

39 F1j6tshnUksvirkjun 9 58 405 6983 6 0.03163 Yes

40 Voroufell 36 52 170 3269 6 0.01074 No 635 Average 2993.5 22,405 7,485 22,405

ITotal Currency rate of exchange £1 - 190.0kr

#Construction cost of switchgear etc. for connection to HV AC System for firm hydro capacity in £m/GWh/yr (£lkWh/yr.).

This results in an increased allocation of system firm capacity in other projects/stations with installed MW but do not have their own installed MW in generators. While they are then

based on MW in other stations the cost benefit is allocated to specific construction projects (dams, etc.). Construction cost of

switchgear etc. for connection to the HV AC System for firm hydro capacity in £m/GWh/yr (£/kWh/yr.) is indicated

The data in Table 1 was downloaded on May 1 2010 from:

http://www.rammaaaetlun.is/media/nidurstada-faghopaNatnsafi­tafla-8mars.pdf

The Energy Investment Cost Groups: Energy, Power and Investment Cost are given in Table 2. The investment costs in columns 7-10 do not include interest during construction. The difference in bounds in columns 3 and 4 reflects the uncertainty associated with the projects within each cost group.

The cost group and the upper and lower bound definitions and explanations given in Table 2 are from:

http://www.rammaaaetlun.is/media/nidurstada­faghopa/Tofluskyringar-virkjunarkostir.pdf

Location of Major Hydro Power Plants, possible Geothermal Plants and HVDC Converter Stations in Iceland for the Proposed Iceland/UK HVDC Cable Link is illustrated in Figure 1. Figure 1 also includes locations for major geothermal sites although these are not included in the present paper.

a e : T bl 2 E t nergy nves men t C t G os roups: E nergy, P ower an d l t nves men t C t os Energy Energy in Unit Cost for Hydro Average Cost Cost Group (£IkWh/yr) Power in

Group (GWh/yr) (£m/GWh/yr) Group Lower Upper Median (MW) bound bound

1 1370 0.14 0.14 183 2 6195 0.14 0.17 0.16 826 3 5097 0.17 0.21 0.19 680 4 7860 0.21 0.28 0.24 1048 5 1248 0.28 0.35 0.31 166 6 635 0.35 0.40 85

Total 22,405 2987

Investment cost in columns 7 - 10 does not include interest during construction Currency rate of exchange: £1 = 190 kr Average utilization time: 7500 h/yr

Investment Cost for

Hydro (£m)

192 978 979

1924 391 254

4718

Difference in bounds in column 3 reflects uncertainty associated with the projects.

AC System Total Unit Connection Investment Investment

Cost Cost (Hydro Cost for (£m) plus AC Hydro

System (£IkW) Connection) (£m/GW)

(£m)

0 192 1050 22.2 1000.2 1184 53.2 1032.2 1441 63.3 1987.3 1836

2349 3000

Table 3. Cost of HVDC Converters, Cable, Cable Mobilisation and Installation & Burial: Iceland/Peterhead

MWRating Cost (£m) Comments HVDC Converters (Pair) 1200 250 Bipole assumed HVDC Cable 1200 1170 Bipole, therefore two cables required. Costs based on £1m/route

km Cable Mobilisation, - 121 Costs based on £5m mobilisation + installation/burial of Installation & Burial £ 1 OOklkm/cct Total - 1541 1.2 OW lInk from Iceland to a landmg pomt at Peterhead Scotland, dIstance 1170km. The four slgmficant figures results from calculatIons, so a test range is £1.SBn--£1.6Bn is of sufficient accuracy for cost analysis Source: Scottish and Southern Energy

3. Cost of HVDC Converters, Cable, Cable Mobilisation, and Installation/Burial: Iceland/Peterhead

This is indicated in Table 3. It corresponds to a 1.2 GW link from Iceland to a landing point at Peterhead Scotland, distance 1170km. The four significant figures results from calculations, so a test range is £1.58n to-£1.68n is of sufficient accuracy for cost analysis which is equivalent to about 2858n to 3058n Icelandic kr.

Cable cost is subject to variation due to movement in the market price of copper, lead and steel, and fluctuations in the exchange rates. The cost of cable mobilisation, installation and

burial is also uncertain and requires a thorough marine survey of the intended route to provide a reasonable estimate but can be considered as typically 8% to 15% of cable cost for long length. This does not include any embedding cost that may be necessary to improve the availability of the cable circuit.

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4. Energy Required at Converter in Iceland, GWh/yr

Table 4 gives the energy in GWh/yr required at the Converter in Iceland for delivered power at 0.6 and 0.9 Load Factor to the AC side of the converter at Peterhead for a Link rated at 0.6 GW, 1.2 GW and 1.8 GW, respectively. Cable and converter losses at rated load are assumed to be 5% and 1 % of link rating, respectively.

T bl 4 E a e nergy R . d t C eqUire a rt . I I d GWh/ r onve er In ce an , 1/'1 Energy (GWh/yr)

Load Factor Link Rating, (GW)

0.6 1.2 1.8 0.6 3,238 6,474 9,713 0.9 5,014 10,028 15,043

Power delIvered to Peterhead 0.6, 1.2, and 1.8 OW Cable losses at rated load assumed to be 5% of Link Rating Converter losses (2) at rated load assumed to be 1.0% of Link Rating

5. Rectifier and Inverter Station Losses

Losses in station equipment have reduced significantly over recent years, and further reductions are anticipated. Typical rectifier and inverter station losses are 0.4%-0.6% of station rating.

Relative converter transformer, thyristor valves, DC smoothing reactor and ac filter losses etc. for a typical HVDC Converter station are depicted in Table 5.

Table 5. Relative Losses in Typical HVDC Converter

Equip ment Converter Transformers Thyristor Valves DC Smoothing Reactors AC Filters Others Total

Values taken from Reference [1]

6. Cable losses

% Losses 51 32 6 7 4

100

Capitalized cost of losses is considered in optimal cable design. This has resulted in the use of larger conductors than have been used in the past. The large cable conductor sizes result in

relatively low transmission losses in comparison to earlier projects. The cable would be designed so that the resistance losses at peak load would be limited to approximately 0.3% to 0.5% per 100km of transmission distance. The thermal rating of the cable for this design would correspond to over twice the rated current of the cable. The thermal rating is not significant as the cable in most part is located in the sea. For a 1200 km HVDC line, cable losses would therefore be between 3.6% and 6%.

Unavailability of the cable and converter stations estimated from the above (very approximate) figures is summarized in Table 6 [1].

Table 6. Unavailability of Iceland/Scotland Link#

Cable 4.2% to 8.3% Converter Stations (2) 0.8% to 1.2% AC Transmission System in Iceland 0.5% Total 5.5 % to 10.0%

#8ased on 1.2 GW cable Values updated from Reference [1].

7. Availability of the Link

Availability of the Link (1.2GW) using very approximate figures is 90% to 95%. The figures are updated from those given in Reference [1]. These figures are similar to those that would be expected of modern gas/coal or nuclear power plants (85% to 90%.

8. Net Effective Costs of Future Power Plants

Table 7A gives cost comparisons for new plant for the Czech Republic in p/kWh; and Figure 78 indicates net effective costs of future nuclear, onshore wind, offshore wind, combined cycle gas/coal and tidal barrage power at January 2010 prices.

For nuclear (40 yrs base line-MIT), capital cost is $4100/kW (£1 = 1.4$), fuel costs is 7% of the capital (see

http://et:J.wikipedia.org/wiklRelative_cost_oCelectricitLgenerate d by different sources : hHp:ffen.wikipedia.orglwiklEconomics of new nuclear power plants

- - - - -

Onshore wind costs 1.5 times less than offshore windl (£400/kW), wave generation costs $611/MWh and tida

generation is £611/MWh. Coal generation costs £107/MWh. The effective cost of the cable link to Iceland compares

very favourably with that of alternative power generation.

Table 7A. Cost Comparisons for New Plant in January 2009 Prices for Czech Republic (p/kWh)

Nuclear Hard Coal Hard Coal + IGCC IGCC+ CCGT (Supercritical) CCS CCS

Capital 3 2 4 2 3 1 Fixed Costs 1 1 1 1 1 0 Fuel Costs 1 2 2 2 2 4 C02 Emissions 0 2 0 2 0 1

Total 5 6 7 6 6 6 Exchange rate. £1- Eur01.15

Table 7 B. Net Effective Costs of Future Power Plants at January 2010 Prices--10% Discount Rate (p/kWh)

Plant Nuclear Onshore Wind Offshore Wind Combined Cycle Tidal Barrage

Capital Charges, etc. 73 8 11 23 76 Inclusive fuel costs 5.125 N/A N/A 152 N/A Lifetime Generating 5 15 21 9.4 N/A (Close to offshore wind) Costs

The above raw data IS consistent with the published data. http.llwww.world-nuclear.orglinfollnf02: html

9. Scheme Development Costs at January 2010 Prices (£m)

Table 8 gives scheme development costs at January 2010 prices for hydro development (including AC system switchgear in Iceland), HVDC cables, converters, and AC transmission system development in Iceland. Cost of hydro development corresponds to load factors of 0.6 and 0.9.

Table 8. Scheme Development Costs at January 2010 Prices (£m)---Taken from Tables 1, 2 & 3 above

Rating Load Development Cost (£m) (MW) Factor a b c d 600 0.6 498.8 706 125 50

0.9 780.3 706 125 50 1200 0.6 1016.1 1291 250 100

0.9 1711.2 1291 250 100 1800 0.6 1614.1 1876 375 150

0.9 2826.4 1876 375 150 a Hydro development (including AC System Connection) b HVDC submarine cables c Converter stations (2) d AC system development in Iceland

Total

1379.8 1661.3 2657.1 3352.2 4015.1 5227.4

Rating in MW is for energy delivered to the AC Network at Peterhead where DC transmission system losses are allowed for.

Cost of hydro development including AC system connection in Iceland evaluated using energy in Energy Cost Groups in ascending order

10. Cost of Delivered Energy

Three contributions should be considered in estimating the cost of delivered energy. These are:

(i) payback of loan on capital investment and interest charges

(ii) running costs including cost of maintenance (iii) losses in cables and converters.

Running costs and cost of maintenance for hydropower are quite low in comparison with other costs and may be ignored in an initial economic assessment. Overall transmission losses are assumed to be as indicated in Section 4.

The average cost of delivered energy is given by:

Cost/kWh = (total payback + total interest charges) = PB (total number of units delivered) U

where PB = I {[component cost] x time / payback period} +

and

+ I [component cost / yr] x [rate of interest]

U = 365 x 24 x [delivered power] x [load factor] x yr

This algorithm is modified appropriately to give the average cost of delivered energy over different times, i.e. 1yr, 25yr, 40yr.

Table 9 gives the cost of delivered energy at the AC side of the converter at Peterhead over the first year of operation at January 2010 prices for 600 MW, 1200 MW and 1800 MW delivered at 0.6 and 0.9 load factor to the AC system at Peterhead corresponding to interest at 4.5%, 6.0%, and 8.0%, respectively. It is assumed that the payback period is 40 yr for hydro and the AC transmission system in Iceland, and 25 yr for converter stations and the HVDC cable.

Availability is assumed to be 100%.

Table 9. Cost of Delivered Energy over First Year at January 2010 Prices (Payback period based on Realistic

Capital Return)

Energy Cost (p/kWh) Rating (MW) 600 1200 1800 Load Factor 0.6 0.9 0.6 0.9 0.6 0.9 Interest (% p.a.) 4.5 3.457 2.721 3.316 2.724 3.328 2.816 6.0 3.766 3.248 3.658 3.255 3.964 3.369 8.0 4.989 3.951 4.795 3.964 4.813 4.106

Payback penod: 40 yr-hydro and AC transmission system In Iceland Payback period: 25 yr-converter stations and HVDC cable Availability 100%

Table 10 indicates ccost of delivered energy to Peterhead over the first year for the payback period based on plant expected life of 80 yr for hydro, and 40 yr for HVDC cables, converter stations and AC system development in Iceland. The cost corresponds to interest at 4.5%, 6.0% and 8.0%, respectively. It is assumed that the Link rating corresponds to power supplied to the converter in Iceland, not that which is delivered to Peterhead.

Comparison of Table 1 0 with Table 9 shows that cost of delivered energy over the first year is less if the payback period is based on system component expected life.

Table 10. Cost of Delivered Energy to Peterhead over First Year at January 2010 Prices (Payback Period based on

Plant Expected Life)

Energy Cost (p/kWh)

Rating (MW) 600 1200 1800 Load Factor 0.6 0.9 0.6 0.9 0.6 0.9 Gen. Energy

(GWh/yr) 3154 4730 6307 9461 9461 14191 Losses (GWh/yr) 142 213 284 426 4.26 639 Unavailability

(GWh/yr) 79 118 158 237 237 355 Del. Energy

(GWh/yr) 2933 4399 5866 8799 8799 13198

Interest (% p.a) 4.5 2.42 1.91 2.32 1.92 2.33 1.98 6.0 3.03 2.41 2.91 2.42 2.92 2.51 8.0 3.88 3.10 3.73 3.12 3.76 3.24

Payback penod: 80 yr for hydro Payback period 40 yr for HVDC cables, Converter stations and AC

System development in Iceland

Availability 100%

Table 11 indicates ccost of delivered energy to Peterhead over the first year of operation, over 25 yr and over 40 yr for the payback period based on plant expected life of 80 yr for hydro, and 40 yr for HVDC cables, converter stations and AC system development in Iceland. The cost corresponds to interest at 4.5%, 6.0% and 8.0%, respectively. It is assumed that the Link rating corresponds to power delivered at Peterhead (not that which is supplied to the converter station in Iceland).

Comparison of Table 11 with Table 10 shows that cost of delivered energy over 25 and 40 yr based on equal annuity analysis for payback period based on plant expected life is less than for the first year. However, the HVDC cables, converter stations and AC system development in Iceland would need renewing after 40 years.

Table 11. Average Cost of Energy Delivered to Peterhead at January 2010 Prices-Equal Annuity Analysis (Payback

period based on plant expected life)

Interest Average Cost (p/kWh) (% p.a.)

Repayment Assumption Rating (MW) 600- 1200 1800 Load Factor 0.6 0.9 0.6 0.9 0.6 0.9 Over 1 yr: 4.5 % p.a. [2.870 2.256 2.747 2.254 2.757 2.329 6.0% p.a. �.527 2.782 3.380 2.786 3.394 2.881 8.0%p.a. �.402 3.485 4.222 3.494 4.243 3.618

Over 25 yr 4.5% p.a. [2.360 1.761 2.268 1.883 2.281 1.952 6.0% p.a. [2.848 2.123 2.741 2.291 2.758 2.378 8.0 % p.a. �.499 2.605 3.370 2.834 3.395 2.947

Over 40 yr 4.5% p.a. 2.059 1.600 1.981 1.660 1.995 1.725 6.0 % p.a. 2.446 1.910 2.357 1.994 2.377 1.969 8.0 % p.a. 2.963 2.323 2.859 2.432 2.887 2.437

Payback penod: 80 yr for hydro Payback period 40 yr for HVDC cables, Converter stations and AC

System development in Iceland Interest charges during construction ignored (this is included roughly in

development cost) Availability 100%

11. Geothermal Energy

During the last 5-10 years, the development of sustainable geothermal and hydropower resources in Iceland has been the most intensive and fastest growing in Europe. It has also more of these energy resources per capita than any other country. A total of about 1250 MW has been developed and some 1300 MW are to come on line within the next decade. Recent projects include the first phases (400 MW) of the Hellisheidi Geothermal Scheme [6].

Table 12 shows the world the technical potential of renewable energy resources (WEA, 2000) [11]. The technical potential is the yearly availability of the renewable resources. These estimates suggest that the technical potential of renewables is sufficiently large to meet future world energy requirements. The present annual consumption of primary energy in the world is about 400 EJ.

Table 12. Technical Potential of Renewable Energy Sources in Exajoules/a

EJ per year

Hydropower 50 Biomass 276 Solar ener!:lY 1575 Wind ener!:lY 640 Geothermal energy 5000 TOTAL 7600

Source: World Energy Assessment (WEA, 2000) [11]

Evidently, a large opportunity to cut GHG emission exists with the geothermal energy sector. However this estimate did not include innovations such as the Iceland Deep Drilling Project (lOOP) [6].

In summary, the long-term program to improve efficiency and economics of geothermal energy by harnessing deep unconventional geothermal resources is an ambitious project to produce electricity from natural supercritical hydrous fluids from drillable depths. Producing higher-temperature fluids for

generation of electric power offers two advantages over using the fluids from conventional wells: (i) higher enthalpy, which promises high power output and higher efficiency per unit mass, and (ii) higher pressure, which keeps the fluid density high and thus contributes to higher mass-flow rates. The choice of technology to be applied for power generation from these high-temperature fluids will be decided after determining the physical and chemical properties of the fluids that are produced.

There are three approaches to improve the economics of the geothermal industry worldwide: (i) cascading the usage of geothermal energy by using the effluent water from electricity production for industrial processes and for domestic heating, (ii) reducing the cost of drilling and completing geothermal production wells, and (iii) reducing the number of wells needed by increasing the power output of each. The best way to achieve the latter is to produce supercritical fluids. Successful completion of the lOOP project is of considerable importance for the geothermal industry at large. A successful outcome would be a major step forward for the geothermal industry on a global scale, which in turn, could help counterbalance the threat of global warming by increased use of sustainable, non­polluting energy resources.

Potential Geothermal developments in Iceland are summarised in:

http://www.rammaaaetlun.is/media/nidurstada-faghopa/Jardhiti­tafla-8mars.pdf

12 Conclusions

The main conclusions are:

(1) Cost of electricity delivered would be very competitive with that from new wind-farms, nuclear, modern gas/coal fired plant, and tidal barrage / tidal stream power.

(2) Availability of the connection should at least equal that from nuclear, and gas/coal fired plant.

(3) No major difficulties are anticipated in manufacturing, laying and repairing the submarine cables or in construction of hydro schemes for the Link.

(4) Expected life for hydro developments is at least 60 years, submarine cables 50 years, and rectifier/inverter stations 30-40 years.

(5) The link could be considerably expanded in future to utilize deep-well geothermal power when the technology is proven

(6) The contribution would make a significant contribution towards UK and European targets for renewable energy. The development would benefit the Icelandic economy, rather than demanding huge amounts out of a heavily damaged economy without supporting necessary recovery.

(7) The Icelandic hydroelectric system is likely to be a perfect match for interacting with the UK/North sea wind energy resources in a similar way as the Norwegian hydroelectric power system

(8) The HVOC UK-Iceland link can serve partly as a one­way exporter of hydroelectric or geothermal energy from Iceland to the UK or it can be considered as a short term bilateral medium for hourly interaction of hydro with marketslwind based on market signals or short term shadow prices. This dual role should be further defined in a negotiation process between the respective national authorities.

13 Acknowledgement

The Authors thank Landsvirkjun, Scottish and Southern Energy, and colleagues for valuable discussions and for

providing advice and data for this study.

14" References

[1] T. J. Hammons, A. Olsen and T. Gudmundsson. Feasibility of Iceland/United Kingdom HVDC Submarine Cable Link, IEEE Transactions on Energy Conversion, Vol. 4, (3), 1989, pp. 414-424.

[2] T. J. Hammons, G. Palmason and S. Thorhallsson. Geothermal Electric Power Generation in Iceland for the Proposed Iceland/United Kingdom HVDC Power Link, IEEE Transactions on Energy Conversion, Vol. 6, (2), 1991, pp. 289-296.

[3] T. J. Hammons, A. Olsen, P. Kacejko and C. L. Leung. Proposed Iceland/United Kingdom Power Link-An In­depth Analysis of Issues and Returns, IEEE Transactions on Energy Conversion, Vol. 8, (3), 1993, pp. 566-574.

[4] T. J. Hammons, K. O. Lee, K. H. Chew and T. C. Chua. Competitiveness of Renewable Energy from Iceland via the Proposed Iceland/UK HVDC Submarine Cable Link. Electric Machines and Power Systems, Vol. 26, 1998, pp. 917-933.

[5] T. J. Hammons. Energy Potential of the Oceans in Europe and North America: Tidal, Wave, Currents, OTEC, and Offshore Wind. International Journal of Power and Energy Systems (IJPES), ACTA Press, Paper 203-4142, Vo1.28, (4), 2008, pp. 416-428.

[6] T J Hammons and A. Gunnarsson. Geothermal Power Developments and Sustainability in Iceland and Worldwide, International Journal of Power and Energy Systems (IJPES), ACTA Press, Paper 203-4494, Vo1.30, (2), 2010, pp. 94-107.

[7] E. B. Hreinsson. Export of Iceland's Hydroelectric Power Using a HVDC Submarine Cable. A report presented to Landsvirkjun (The National Power Co), September 1986.

[8] E. B. Hreinsson. Renewable Energy Resources in Iceland - Environmental Policy and Economic Value. An invited paper Proc. of the Nordic Conference on Production and Use of Renewable Energy, 9 -11 of July, 2008, Vaasa, Finland (Invited paper).

[9] E. B. Hreinsson. The Economic Rent in Hydro and Geothermal Resources in Iceland with Reference to International Energy Markets and Resource Cost Structure, Proc. of the 2008 IEEE PES General Meeting, July 20-24, Pittsburgh, PA, USA.

[10] E. B. Hreinsson. Environmental, Technical, Economics and Policy Issues of the Master Plan for the Renewable Hydro and Geothermal Energy Resources in Iceland, Proc. of the International Universities Power Engineering Conference, (UPEC2007), Brighton, United Kingdom, September 4th-6th, 2007.

[11] WEA. World Energy Assessment: Energy and the Challenge of Sustainability. Prepared by UNDP, UN-DESA and the World Energy Council. United Nations Development Programme, New York, 2000, 508. 8.

Biographies

Thomas James Hammons received the degree of ACGI from City and Guilds College, London, U.K. and the B.Sc. degree in Engineering (1 st Class Honours), and the DIC, and Ph.D. degrees from Imperial College, London University, UK.

He is a member of the teaching faculty of the Faculty of Engineering, University of Glasgow, Scotland, UK. Prior to this he was employed as an

Engineer in the Systems Engineering Department of Associated Electrical Industries, Manchester, UK. He was Professor of Electrical and Computer Engineering at McMaster University, Hamilton, Ontario, Canada in 1978-1979. He was a Visiting Professor at the Silesian Polytechnic University, Poland in 1978, a Visiting Professor at the Czechoslovakian Academy of Sciences, Prague in 1982, 1985 and 1988, and a Visiting Professor at the Polytechnic University of Grenoble, France in 1984. He is the author/co-author of over 400 scientific articles and papers on electrical power engineering. He has lectured extensively in North America, Africa, Asia, and both in Eastern and Western Europe.

Dr Hammons is a Fellow of IEEE (1996), is Past Chair of International Practices for Energy Development and Power Generation of IEEE, and Past Chair of United Kingdom and Republic of Ireland (UKRI) Section IEEE. He is a Past Chair of the IEEE PES Task Force on harmonizing power-engineering standards worldwide. He received the IEEE Power Engineering Society 2003 Outstanding Large Chapter Award as Chair of the United Kingdom and Republic of Ireland Section Power Engineering Chapter (1994-2003) in 2004 and the IEEE Power Engineering Society Energy Development and Power Generation Award in Recognition of Distinguished Service to the Committee in 1996. He also received two higher honorary Doctorates in Engineering. He is a Founder Member of the International Universities Power Engineering Conference (UPEC) and is Past Permanent Secretary of UPEC. He is a registered European Engineer in the Federation of National Engineering Associations in Europe.

Egill Benedikt Hreinsson received the First Part of his Engineering Degree from the University of Iceland, the MSc. in Electrical Engineering from the University of Lund, Sweden and the MSc. in Industrial and Systems Engineering from Virginia Tech, Blacksburg, VA. In 1972 he joined Landsvirkjun, the National Power Co. of Iceland, Reykjavik, working on SCADAIEMS, telecommunication and telemeter systems, power system

planning and analysis of hydroelectric system operations and expansion. In 1982 he joined the Department of Electrical and Computer Engineering, Faculty of Engineering, University of Iceland, where he is currently a professor in the Department of Electrical and Computer Engineering. He is the recipient of the Thor Thors award. He has been an associate consultant in USA with KEMA consulting and in Europe (including Iceland) in the fields of electric power systems, communications and computer applications in energy systems. He is a senior member of the IEEE and member of the Association of Engineers in Iceland: He chaired the Iceland Department of Industry Committee for the re-evaluation of Electric power safety. His research and teaching interests include power system analysis, economics and operations planning in addition to the application and merging of the arts in engineering and science. He is the author/co-author of over 150 scientific and technical articles and papers on electrical power engineering, management and economics. He is also a jazz pianist and has

been on the board of the Reykjavik Jazz Festival and the Suzuki Music School in Reykjavik. He has played extensively in Iceland and elsewhere.

Piotr Kacejko graduated with an MSc from the Faculty of Electrical Engineering, Lublin University of Technology, Poland. He has been a member of the teaching faculty of this

university for 25 years. He received PhD degree and DSc degree from Lublin University of Technology and Warsaw University of Technology, respectively.

He was also employed as a Consultant Engineer in the Power Distribution Company Lubzel Ltd. and with the Polish National Grid Company (PSE). He spent a couple of months as a research fellow with the Faculty of Engineering, University of Glasgow, UK. Since 2006 he is a full professor and the head of

the Power Engineering Department, TU Lublin. He is the co­author of over 100 papers and 4 books on power system analysis, protection problems and reliability enhancement. Prof. Kacejko is also co-author of commercial software used for short circuit analysis (SCC). He works as an expert and a consultant for companies that are planning connection of power sources (plants, and wind farms) to the grid. He is a member of IEEE.