Report No 3882-PNG

Papua New Guinea: Issues and Optionsin the Energy Sector

June 1982

Report of the joint ULMP/Mfdd Bank Energy Sector Assessment ProgramThis document has a restricted distribution. Its contents may not be disclosedwithout authorization from the Government, the UNDP or the World Bank.

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CURRENCY EQUIVALENTS

Currency Unit = Kina (K)1 Kina = 1.5 US Dollar (1981)

1 US dollar = K 0.674 1 Kina = 100 toea (t)

FISCAL YEAR

July 1 - June 30 through 1977

Jan. 1 - Dec. 31 beginning in 1978

ABBREVIATIONS

BCL Bougainville Copper Ltd.BOE Barrels of Oil EquivalentDME Department of Minerals and EnergyEDC Energy Development CorporationELCOM Electricity CommissionEPU Energy Planning UnitMMCF Million Cubic FeetMMCFD Million Cubic Feet per DayNEPC National Energy Planning CouncilPNG Papua New GuineaTCF Trillion Cubic FeetTOE Tons of Oil Equivalent

CONVERSION FACTORS

Density Net Cal. Value Tonne of Oil Equivalent(MJ/kg) (TOE)

Light Distillates 0.68 44.5 1.063

Gasoline 0.73 44.1 1.053Avtur/Kerosene 0.78 43.5 1.038Distillate 0.83 42.6 1.018Residual Fuel Oil 0.97 40.4 0.965Methanol 0.796 19.95 0.476Coat1 (Australian) 27.64 0.660

This report is based on the findings of an energy sectorassessment mission comprising Messrs. N. B. Prasad (missionleader), Donald King, John Tatom, David Newbery and Ms. HudaKraske which visited Papua New Guinea in November 1981.Secretarial assistance was provided by Beatrice J. Moses. Thereport was discussed with the Government in June 1982.

FOR OFFICIAL USE ONLY

Report No. 3882-PNG

PAPUA NEW GUINEA

ISSUES AND OPTIONS IN THE ENERGY SECTOR

June 1982

This is one of a series of reports of the Joint UNDP/World BankEnergy Sector Assessment Program. Finance for this work hasbeen provided, in part, by the UNDP Energy Account, and the workhas been carried out by the World Bank. This report has arestricted distribution. Its contents may not be disclosedwithout authorization from the Government, the UNDP or the WorldBank.

TABLE OF CONTENTS

Page No

I- SUMMARY AND CONCLUSIONS.1 ...... ..-- 1

Energy Consumption ................................. 2Energy Forecast 1985 and 1990 . 3

Deiand . 3Supply . 4Investment. 6

Energy Resources. 7Electricity. 7Oil and Gas. 9Coal. 9Geotherraal .10Renewables ............ 10

Institutional Issues .12Priorities for Action .13Framework for Technical Assistance .14

II. ENERGY CONSUMPTION AND PRICING .15

Consumption Overview .15The 1980 Energy Balance .18Sectoral Pattern of Energy Consumption .18

Transport .18Industry .19

Bougainville Copper Ltd (BCL) .20Non-Mining Industries .21

Agricultural Processin .22Others .23

Agriculture .23Households .23

Energy Pricing, Taxes and Subsidies .24Electricity .24Petroleum Products .25

III.. ENERGY RESOURCES. ISSUES AND OPTIONS .............. 27

Resource Overview .27Electricity .27Oil and Gas .31Coal .34Geothermal .36Renewables .36

Woodfuels ................................. 36Ethanol .37Biogas .39Mini and Micro-Hydro .40Solar Water Heating .40Photo-voltaic Cells .41Wind - Electric Generation .41

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TABLE OF CONTENTS (cont'd)

Page No.

IV. ENERGY OUTLOOK 1981-1990 ........................... 42

Introduction ....................................... 42Electricity . ....................................... 42The Transport Sector ... 45Industry ........................................... 45Other Sectors (Agriculture, Households, etc) ....... 46

V. INSTITUTIONS AND POLICY PLANNING .51

Introduction........ ... 51The Geological Survey Department.. 51The Energy Planning Unit .... 52ELCOM .... 53Bureau of Water Resources ... 55

VI. ENERGY SECTOR INVESTENT.. 56

ANNEXES

I: Energy Balances (1970 - 1990) . .59II: The Electric Power Sector. 72III: The Transport Sector .. 77IV: PNG Hydroelectric Potential 83V: Coal Occurrences in PNG . .84

VI: Organization Chart of the Department of Mineralsand Energy . .85

VII: Consumption, Price and Import Cost Data 86

MAP STwffl Issues and Options in the Energy Sector....16180 Ethanol Fuel Proposals..

CHAPTER I

SUMMARY AND CONCLUSIONS

1.01 Papua New Guinea (PNG), with a population of 3 million, isrelatively well-endowed with energy resources - hydro potentialconservatively estimated at 14,000MW, gas reserves (from six discoverywells) already estimated at a possible 1.5 to 5.0 trillion cu. ft. withlarge sedimentary basin areas yet to be explored, a large biomasspotential from its forests and good solar energy potential. Despitethis, PNG is currently dependent on petroleum product imports for meetingmost of its commercial energy needs. Petroleum products account fornearly 55% of all energy consumption and 87% of all commercial energyconsumption. Because of rising world oil prices and increasing demandfor petroleum products, the share of export revenue spent on oil importshas risen from about 3% in 1972 to an estimated 24% in 1981. The 1981oil imports are estimated at US$209 million (CIF) and amount to over 8%of GNP, 30% of gross domestic investment, and 80% of net externalassistance. Without major efforts by the government, energy imports willsoon impose an intolerable burden on the economy.

1.02 The country's energy options are severely constrained by thesmall size of total domestic energy demand, as well as the geographicalfragmentation of the market, which leads to high investment and operatingcosts per unit of output. Careful planning is therefore essential todetermine the appropriate options available for substituting importedpetroleum products by indigenous energy sources. In recognition of this,the Government of PNG established in 1978 an Energy Planning Unit (EPU)in the Department of Minerals and Energy (DME) and by 1979 had issued a"White Paper" outlining its energy objectives and policies. The "WhitePaper" emphasized the role of renewables in alleviating PNG's energyproblems, particularly ethanol for the transport sector (which consumes45% of all petroleum products), wood pyrolysis for the industrial sectorand solar water heating and photovoltaics for households, and EPU beganpromoting projects in these areas, many of which, following furtheranalysis and feasibility studies, have since been abandoned or reduced inscope. More conventional areas of activity tended to be neglected andenergy planning did not advance significantly. However, in late 1980 theEPU began to place more emphasis on the electricity sub-sector, where 40%of petroleum products are used, where multiple options are available forsubstituting the oil used in power generation and where severe andwidespread operational and financial difficulties were beingexperienced. More recently, some attention is being paid to theprospective use of onshore and offshore reserves of natural gas, to hydrodevelopment and to energy conservation. Energy planning, includinganalysis, policy and monitoring for the entire energy sector, coveringall producer and user sectors and sub-sectors, still has to mature and inthis report the mission makes various recommendations for developing andstrengthening the energy planning process. In addition to institutionalstrengthening there is an urgent need to implement further studies toevaluate more fully the different energy supply options, especially those

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that will lead to firming up reserves of gas and oil, hydro and coal, sothat decisions on which combination of energy sources is optimal tosatisfy the medium-to-long-term demand of the various user groups can betaken in the near future.

Energy Consumption

1.03 The energy sector of PNG has developed alongside the variousenclaves which have characterized the country's industrial, economic andurban development. The major enclave is Bougainville Copper, Ltd. (BCL),which is on Bougainville Island separated from the country-s major demandcenters, and which consumes nearly 62% of all electricity generated and40% of all petroleum products, either for power generation or asdistillates for various mining and ore processing operations, such ascrushing, drying, etc. Another copper mining enclave, Ok Tedi on themain Island of New Guinea close to the Indonesian border, is beingdeveloped and will start production in the mid-eighties. The country'surban enclaves, which have a large expatriate population whose pattern ofliving is set by modern developed country standards, consume most of theremaining electricity and petroleum products in the household, commercialand private transport sectors. Over half of the country's 32,000household consumers of electricity in 1980 were in the two towns of PortMoresby and Lae, whose combined population is only 180,000 (6% of thetotal population of 3 million). The consumption of commercial energy inthe rural sector (87% of population) is a meager 1.1% of the country'stotal commercial energy consumption.

1.04 Total primary energy consumption in 1980 is estimated at1,143,000 tonnes of oil equivalent (TOE), of which 709,000 TOE (62%) iscommercial energy, mostly in the form of petroleum products, and 434,000tonnes (38%) is non-commercial energy, mainly fuelwood. Per capitaconsumption of total energy at 2.8 barrels of oil equivalent (BOE) isapproximately the same as in middle income developing countries in Asia(Indonesia 2.2 BOE, Thailand 2.7 BOE, Philippines 2.8 BOE) though thepattern of consumption, as noted above, is substantially different.

1.05 PNG has become increasingly dependent on commercial energy inthe past decade. Commercial energy consumption (mainly petroleumproducts) grew from 44% of total energy consumption in 1970 to 62% in1980. The commercial energy/GDP ratio has grown at a much faster rate(7.8%) compared to the total energy/GDP ratio (4.2%) over the last tenyears. The increase in oil consumption is partly due to the use of oilfor power generation and continuous operation of the gas turbine in PortMoresby, which was originally intended only as a stand-by, and to thestart-up of operations by BCL.

1.06 The transport and electricity sectors consume nearly 45% and 40%of all petroleum products respectively. The growth rates of these twosectors, and especially the strategy adopted for future power generationamong many available options (hydro, oil, gas, coal), will largelydetermine the growth of petroleum product consumption. Industry(including agricultural processing but excluding BCL) accounts for only

14% of electricity consumption (of which nearly a third is from captiveplant) and 6% of petroleum product consumption. Both industry andcommerce have suffered from the unreliable public electricity supply andhave been forced to own and operate captive generating plants, mainly inthe form of small diesel sets. In addition, there is also substantialsuppressed demand for electricity because ELCOM, beset by its ownmanagement and financial problems, has not been able to fulfill its roleadequately as a public utility with the responsibility of providingreliable power to all consumers at reasonable cost.

1.07 The pattern of final energy consumption in 1980 is given inTable 1.1 below:

Table 1.1 1/

PNG: Final 2/ Energy Consumption Pattern, 1980(000 tonnes of oil equivalent)

TotalCommercial Total Energy

Elec. Pet.3/ TOE % Woodfuel 4/ TOE %

Households 10 18 28 (6) 386 414 (46)Industry 80 73 153 (32) 48 201 (22)Transport - 275 275 (58) - 275 (30)Others (Agricul-ture & Commerce) 12 5 17 (4) - 17 (2)Total 102 371 473 (100) 434 907 (100)

1/ Annex I Tables I.4 and I.5 (1980 Energy Balances) contain data onprimary energy consumed.2/ Net of transformation losses of 236,000 TOE.3/ Does not include petroleum products used for power generationequivalent to 248,000 tonnes of oil (40% of total petroleum products),included in the electricity produced.4/ Estimated.

Energy Forecast 1985 and 1990

Demand

1.08 Forecasts made by the Bank suggest a GNP rate of growth of 4%per annum over the decade, perhaps higher in the early part as Ok Tedistarts production. (By 1986 this mine might account for an additional10% of GNP, suggesting that growth elsewhere may be below 4%.) This iscomparable to growth over the past decade, during which energy demandgrew steadily. Based on assumed sectoral growth rates, projections madefor BCL and Ok Tedi, and population growth rates, energy demand forcastshave been made for 1985 and 1990, and are summarized in Table 1.2 below:

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Table 1.2

Forecast Final Energy Consumption Pattern for 1985 and 1990(-000 TOE)

Electricity Petroleum Woodfuel Total

1985Households 12 22 430 464Industry 126 93 - 219Transport - 297 - 297Others (Agr. and

Commerce) 15 8 70 93

Total 153 420i/ 500 1,073

1990Households 17 28 473 518Industry 172 122 - 294Transport - 367 - 367Others (Agr. and

Commerce) 20 9 88 117Total 209 526_/ 561 1,296

Growth Rates (%) 3/

1980-85 8.5 2.5 2.9 3.41985-90 6.4 4.6 2.3 3.91980-90 7.4 3.6 2.6 3.6

1/ Does not include 392,000 TOE used for power generation, alreadyincluded under electricity.2/ Does not include 475,000 TOE used for power generation, alreadyincluded under electricity.3/ Historical growth rates in final energy consumption during theseventies are as follows:

1970-75 9.3% (BCL started operation in 1973)1975-80 3.6%1970-80 6.4%

Supply

1.09 Not much can be done on the supply side to alter the picture for1985 due to the short-lead time available. However, the mission assumedthat BCL may, by then, switch to coal-fired thermal plant (2 x 45 MW),instead of continued reliance on fuel oil. The options available for1990 are numerous and for the purpose of illustrating a few of theseoptions and the magnitudes involved, three preliminary supply scenarioshave been quantified by the mission: (a) Case A (Gas) assumes that Pascagas field will be developed and gas piped to Port Moresby for power

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generation and possibly methanol production while hydro is beingdeveloped at BCL; (b) Case B (Coal) assumes tht a 25 MW coal-firedthermal station will be built in Port Moresby, and BCL will switch tocoal; (c) Case C (BAU) describes business as usual scenario withcontinued dependence on imported oil.

1.10 Condensed energy balances for 1990 appear in Annex Icorresponding to the three scenarios outlined above and summarized belowin Table 1.3:

Table 1.3

Energy Required in 1990 Under Three Possible Scenarios('000 TOE)

Case A Case B Case C

(Gas) 1/ (Coal) (BAU)

ProductionGas and Condensates 302 43 43Hydro 2/ 304 197 243

Plus ImportsCoal 304 447 -Petroleum 573 598 988

Less ExportsCondensates -178

Total Commercial Energy Available 1305 1285 1274

Less Transformation losses(generation and other losses) -570 -550 -538

Total Final Commercial EnergyConsumption 735 735 735

Non-commercial Energy 561 561 561

Total Final Energy Consumption 1296 1296 1296

1/ Annex I Table I.8 also shows Case A (Gas) in detail without theproduction and export of methanol.2/ Assuming 28% efficiency.

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Investment

1.11 Table 1.4 shows possible investment outlays in the energy sectorfor each of the scenarios mentioned above:

Table 1.4

Investment in the Energy Sector 1981-1990 1/(Million US Dollars)

Case A 2/ Case B Case C

(Gas) (Coal) (BAU)

ELCOMInvestment to 1985 2/ 130.0 130.0 130.0Other investment 15.0 15.0 15.0Port Moresby electricity 12.0 43.5 67.5

Gas Field Development 150.0Gas Pipelines to Port Moresby 90.0

BCL - Hydro 150.0BCL - Coal 132.0 200.0 49.5

Ok Tedi Diesel 18.0 18.0 18.0Ok Tedi Hydro 150.0 150.0 150.0

Total 847.0 555.0 430.0

1/ Excluding investment in oil and gas exploration at or over US$30million per annum.2/ Does not include investment in a methanol plant (roughly estimated atUS$300 million for a 2,000 tons per day capacity) consideredd as apossibility under Case A.3/ Includes investment in Barikewa gas turbine and Rouna 4 ($71.0 m),Pauanda ($9.6 m), and Warrangoi ($49.4 m).

1.12 The direct balance of payments implications of these three scenariosare shown in Table 1.5 below:

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Table 1.5Forecast Net Fuel Imports 1985 and 1990

(1980 US$)

1980 1985 1990 2/A B C

(Gas) (Coal) (BAU)

Imports of fuels in TOE 619 812 877 1045 988Cost of fuel imports (million US$) 188.0 287.0 290 319 381Less energy exports (million US$) 1/ - - 71 - -

Net Energy import cost (milion US$) 188.0 287.0 219 319 381

1/ Condensates only, i.e. no methanol exports included (valued at aboutUS$138 million).2/ 1990 prices based on Table VII.9 of Annex VII.

1.13 If total exports of goods and services grow at 4% per annum from1985-1990 (as assumed in Bank calculations), they will yield $1750million in 1990 (1980 prices). Net imports of energy in 1990 range from$219-$381 million, or from 13%-22% of export revenue. If methanol isproduced and exported as envisaged under Case (A) the economics of thisoption become extremely favorable. A 2,000 ton per day plant would beable to produce about 660,000 tons per annum. At about US$ 210/per ton,this would yield an additional US$138 million in foreign exchange,reducing the import bill under Case A to US$81 million or 5% of exportearnings (which is below its share in 1969-70).

1.14 In sum, although larger quantities are imported in Case B thanin Case C, the import bill is lower because cheaper coal substitutes formore expensive fuel oil used in Case C. Case A has an additionalattraction in that it provides gas at Port Moresby for an export orientedpetrochemical industry such as methanol. Although Case A (Gas) withoutmethanol exports is attractive, it looks even more so with methanolexports. Thus, in spite of the fact that investment costs in Case A arethe highest, such investment will result in drastically reducing thecountry's oil imports.

1.15 These scenarios have been done only for the purpose ofillustrating the options available in the energy sector and the order ofmagnitude of energy imports and their costs. Detailed studies will berequired to estimate the profitability or otherwise of the differentcomponents of these three scenarios, or other scenarios. In any event,potential investments in this sector will be dependent upon theavailability of the resources necessary to finance these investments evenassuming acceptable levels of profitability.

Energy Resources

Electricity

1.16 PNG-s largest energy resource is its hydroelectric potential withmany potential hydroelectric sites, particularly on the Fly, Purari andKikori Rivers flowing into the Gulf of Papua and the Musa River flowing

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into the Oro Bay. The total potential is conservatively estimated at14,000 MW (or nearly 5 kw per capita, one of the highest in the world).However, because of the fragmented nature of the country and limiteddemand in any one locality, development of large hydro resources has notbeen feasible and only some of the smaller run-of-river schemes have beenimplemented. One difficulty in planning hydro development is the lack ofstream gauging records for all except the largest rivers, and the missionrecommends that urgent action be taken to introduce new gauging stationson potential hydro sites for which no records exist. Attempts have beenmade to synthesize data from general rainfall records, thecharacteristics of similar streams, and from gauges installed in therelatively short period when any given project is under consideration.Hydro plants installed on the basis of such inadequate data have not metexpectations and both minimum and average flows are seriously below theamounts designed for. Consequently, it has been necessary to providethermal back-up (based on petroleum products) to deliver much of theenergy required. Given the nature of the hydro schemes in operation andunder consideration, thermal back-up will continue to be essential andshould be included in all power sector plans.

1.17 Plans for future power generation must include some or all ofthe following:

(i) First, by expansion of existing hydro sites and adetailed investigation of other possible sites forfeeding the Port Moresby/Ramu grids. The missionsupports, subject to a detailed economic appraisal,ELCOM-s present plans to build another hydroelectricpower station (Rouna 4) in the Port Moresby area sincethis is the only hydro option available in the short-to-medium term that will add to the energy available.However, as with other hydroplants, this will have a lowfirm plant factor, perhaps no more than 20% in dry years,which will be insufficient to supply the demand on thePort Moresby systems which has a load factor over 60%.At present, a gas turbine at Port Moresby is being usedto meet the shortfall in dry years and some form ofthermal back-up will continue to be needed.

(ii) Second, by the use of imported coal at BCL and PortMoresby. In the latter case, the mission stronglyrecommends a reappraisal of the 25 MW coal-fired thermalplant proposed by consultants C.T. Main, who werecommissioned by DME to investigate the options for powersupply in the Port Moresby area.

(iii) Third, by use of natural gas resources, particularly theBarikewa reserves for the Ramu grid but also, possibly,the Pasca/Uramu reserves for the Port Moresby grid.

(iv) Fourthly, by using wood-wastes for power generation forthe Ramu grid, which the mission considers worthy of

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further examination, although the mission concurs withELCOM's views that wood supplies in the Port Moresby areaare insufficient to sustain even a 10 MW wood-burningplant on a long-term basis.

(v) Since other mining metallurgical enclaves (besides OkTedi) are being considered the mission recommends that aninventory of all major hydro sites (over 50MW) becompiled and from this list preliminary feasibilitystudies of 3-4 selected hydro sites for such enclaves bestarted.

(vi) Finally, least cost studies of the various alternativesof expanding the ELCOM power system be continued over alonger (15-20 year) time frame.

Oil and Gas

1.18 Substantial exploration work has been done in the oil and gassubsector in the past fifty years, with mainly gas finds. RobertsonResearch's report, reviewing and cataloging all work done to date, is nowready. The Papuan Basin contains most of the gas found, mainly in twooffshore wells (Pasca and Uramu) and four onshore wells (Barikewa, Iehi,Bwata and Kuru). On the basis of these discoveries, gas reserves areestimated to be 1.5-5.0 trillion cubic feet (TCF).

1.19 The pressing need for hydrocarbon fuels in the economy, coupledwith the availability of gas, calls for a greater sense of urgency inusing this valuable resource. As the situation now stands, the oilcompanies have little incentive to develop the proven reserves fordomestic use for power considering the small fragmented demand centersand degree of industrialization of the country, unless they can beassociated with export-oriented industries. The Government shouldtherefore:

(a) Require speedier exploration and appraisal of discoveriesalready made by oil companies as their work programs comeup for periodic review under the terms of the licencesalready granted. If possible reserves are considered toosmall for export (as may be the case with Barikewa)consideration should be given to providing incentives tothe oil companies for developing such fields for thedomestic market or alternatively, persuading them torelinquish the areas concerned.

(b) Carry out as soon as possible a gas utilization study onthe onshore-offshore gas fields, mainly to establish thefeasibility of development of each of the individual gasfields, and evaluate a combination of gas utilizationoptions including: (1) a gas-fired power plant usingonshore gas from Barikewa with transmission to the RamuSystem in the north and possibly to Port Moresby; (2) a

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pipeline from Pasca and/or Uramu to Port Moresby for powergeneration including recovery of condensates and LPG; (3)methanol production for local and export markets. (4) anLNG plant (somewhere in the range of 75-500 mmcf/dcapacity); and (5) ammonia/urea production.

Coal

1.20 Coal occurrences have been found in the Morobe and GulfProvinces and near Madang but no active follow-up work has beenconsidered necessary to firm up reserves. They have generally been smalldeposits of low grade coal with seams dipping at moderate angles. Fromthe meager data available, it is likely that technically recoverablereserves exist in both Morobe and Gulf Provinces and that Pindiu, Purariand Hohoro areas may be the most promising. The viability of open cutmines in these areas should be examined for the purpose of powergeneration in Lae and Port Moresby as an alternative to the use ofimported steam coal, after more geological work and the firming up ofreserves has been done. For this prupose the reserves required aremodest (about 5 millin tons) and it is likely that external technicalassistance will be available.

Geothermal

1.21 There are surface evidences of hydrothermal activity in the formof seeps and geysers at temperature of 900/950C, particularly in theRabaul, Hoskins and Talasea thermal areas of New Britain and the Deideiand lamalele thermal areas of Fergusson Island. As electricityconsumption in these areas is small and there is no consumption of steamfor process purposes, there is no urgency in developing the potential,but some priority may be given to identifying the potential of the Rabaulthermal areas.

Renewables

1.22 PNG has had a comprehensive program to produce energy fromrenewable sources. The main objective of the renewables program has beento substitute oil in the transport sector by ethanol, produced fromcassava, sugarcane, molasses or sago palm. However, many of the projectsoriginally included in the program were based on technology that had notbeen perfected; scarce funds have already been spent on experimentalventures with disappointing results. The eventual potential for energyproduction from these sources might be immense, but their technical andeconomic viability needs to be proven with minimal expenditures,particularly in the context of potential development of oil and gas.

(a) Ethanol: Considerable emphasis has been placed on developing

ethanol from biomass as a substitute for motor fuel. A cassava-based project at the Baiyer River is under development atpresent, and studies have been undertaken for at least fourother projects (based on molasses, cassava plus sugarcane,sugarcane, and sago palm respectively). A potential six million

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litre/annum molasses-based project in the Ramu Valley seemseconomically attractive, but it is unlikely that any other newprojects will prove viable. The economic justification forcompleting the Baiyer River Project is only marginal. EPU'spublished target in 1979 of 130 million litres per annum by 1990has been recognized as unrealistic and has been reduced first to36 million and more recently to 10 million. The Governmentshould carefully review the economic justification of anyfurther investment in ethanol projects;

(b) Wood: Wood resources are tremendous (covering 40 millionhectares) and fuelwood contributes about 40% of total energyconsumption. Nearly 95% of the fuelwood is consumed inhouseholds, the remaining 5% being consumed in the industrialsector, particularly agricultural processing where it accountsfor about 62% of all energy use It is expected that theconsumption of fuelwood will rise in proportion to the increasein population growth. The scope for its utilization in theindustrial sector for heat and for power generation needs closerstudy. Attempts at using pyrolysis of wood wastes in industryat Lae have failed due to various technical difficulties.Gasification has only been attempted on an experimental scale.Studies for the utilization of the considerable wood wastesthrough wood gasification and steam generation should continueto be made. The possibility of running small diesel generatingsets with wood gas in remote areas needs to be pursued as thetechnology is fairly well proven. Wood burning conventionalpower generation has been considered by ELCOM and rejected, butmay be worth a second look, particularly at Lae-Bulolo.

1.23 With respect to other renewables:

(i) The mission supports EPU's decision that no furtherinvestment in biogas should be made. In any event, thebiogas plant in Lae has failed and the one installed atWaghi Mek Coffee Plant is inoperable due to technicaldifficulties.

(ii) The mission also supports EPU's decision to halt further

investment in pyrolysis due to the technical difficultiesencountered in using the wood wastes in the Lae area.

(iii) Solar water heating has had great success in residentialand commercial buildings and is economically viable. Themission commends the measures taken by Government forthis purpose, especially the provision of tax incentivesfor the installation of solar water heaters.

(iv) Photo-voltaic cells are very expensive and are not

economically viable at present given the very lowconsumption of kerosene for lighting purposes in rural

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households. As the cost of cells declines in the futurewith improved technology, further investment in them forother applications, particularly in telecommunications,may become more attractive, and therefore the current,relatively low, levels of funding may continue.

Institutional Issues

1.24 In the petroleum subsector, the Geological Survey Divisionwithin the Department of Minerals and Energy has responsibility fortechnical advice on all matters concerning oil and gas, coal andgeothermal energy. However, the same Division is also responsible forsimilar activities in the mining sector, which due to its importance inthe economy, tends to receive higher priority, leading to some neglect ofthe energy sector. A small group of expatriates and PNG nationals, allgeologists and geophysicists, look after both minerals and oil and gas.There is no staff experienced in petroleum matters. In view of theimportance of oil and gas, the Geological Survey Division ought to bestrengthened by drawing on outside expertise to oversee theimplementation of the Government's exploration policies and eventually,as delineation of reserves progresses and commercial discoveries are madeand developed, the option of having a separate agency for oil and gasshould be considered.

1.25 In the power sector, mismanagement, lack of planning and, untilrecently, tariffs that did not reflect cost, were the primary cause ofELCOM's financial difficulties and the power shortages in the late1970s. The situation further worsened in 1980/81 due to failure of thehydro system 1/ and the larger reliance on diesel-fuelled turbines.However, it is only fair to point out that some of the trouble originatedfrom policies and actions taken before independence, and despite attemptsaimed at speedy improvement, it has been difficult to catch up. Inaddition to a new General Manager, who has been recruited for a five-yearcontract, four technical staff from Montreal Engineering Inc., have beenhired for three years to help run ELCOM, and this is likely to improvematters.

1.26 The Energy Planning Unit should continue to be part of theDepartment of Minerals and Energy. However, its size, role and emphasisshould be redefined as follows:

(i) EPU should function as an overall energy study andplanning agency for all the energy subsectors includingoil and gas, power, and coal, and not focus mainly onrenewable energy planning. In order to make realisticdemand forecasts for all energy subsectors, EPU shouldwork closely with ELCOM and the various agencies dealingwith the primary energy subsectors and the Forestry

1/ Exemplified by turbine breakage, siltation, drought, etc.

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Office of Department of Primary Industries (DPI). EPU'sexpertise should be diversified so that it can handlethese new responsibilities as well as effectively monitorenergy policies, programs and conservation measures.

(ii) In order to emphasize the importance of overall energyplanning, the promotion and implementation of renewableenergy projects and conservation measures could beentrusted to a separate unit under the Planning andPolicy Division.

Priorities for Action by PNG

1.27 Among the various recommendations made in this report, themission considers that priority should be given, or continue to be given,to:

(a) Inducing the oil companies drilling in PNG to accelerate theirexploration activities in an effort to firm up reserves of oiland gas and reach agreements on the development of alreadydiscovered gas fields (paras. 1.19 and 3.24).

(b) Completion of a gas utilization study on the onshore - offshoregas fields (paras. 1.19 and 3.22).

(c) Urgent reconsideration by ELCOM of a 25 MW coal-fired thermalplant for Port Moresby and, if viable, development as soon aspossible (paras 1.17 and 3.11).

(d) Creation of a group of outside specialists for oil and gaswithin the Department of Minerals and Energy to emphasize andgive a greater sense of urgency to more intensive explorationactivities by the oil companies and monitor trends andoperations in the subsector (paras. 1.24 and 5.03).

(e) Redefinition of the role of EPU within DME so that it canfunction as an overall energy planning agency, and creation of aseparate unit for the implementation of renewable energyprojects and conservation measures (paras. 1.26 and 5.06).

(f) Confining work on ethanol to the Ramu project and to critical

evaluation of all other proposals (paras. 1.22 (a) and 3.37).

(g) Investment in gauging stations on small rivers in PNG (paras.1.16 and 3.07).

(h) An inventory of all major hydro sites (over 50 MW), from which

3-4 large hydro sites should be selected for feasibility studiesfor possible use by metallurgical enclaves (paras. 1.17 and3.14).

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(i) Finally, least cost studies of the various alternatives ofexpanding the ELCOM power system be continued over a longer (15-20 years) time frame (paras. 1.17 and 3.16).

Framework for Technical Assistance

1.28 To assist the Government in implementing many of therecommendations made above, the mission strongly recommends thattechnical assistance financed by the Bank, ADB, UNDP or other donors bemade available to carry out the following urgently needed activities:

(a) US$1-1.5 million gas utilization study on the onshore-offshoregas fields, possibly within the context of the on-goingpetroleum exploration project;

(b) US$1-1.5 million for an inventory of major hydro sites andpreliminary feasibility studies of 3-4 large hydro sites todetermine their potential for use by an enclave metallurgicaloperation;

(c) US$1.0 million for financing about 75 new gauging installationson small hydro sites for which there are no flow records;

(d) A series of wood and wood-waste utilization studies;

(e) Delineation work on coal reserves for domestic use in thermalpower plants; and

(f) Institutional strengthening for EPU to enable it to function asan overall energy planning agency.

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CHAPTER II

ENERGY CONSUMPTION AND PRICING

Consumption Overview

2.01 Total energy consumption in PNG in 1980 is estimated at1,143,000 tonnes of oil equivalent (TOE) of which 709,000 TOE (62%) iscommercial energy and 434,000 TOE (38%) non-commercial energy, mainlywoodfuel. Per capita consumption of total energy is approximately 2.8barrels of oil equivalent (BOE), which is the same as in middle incomedeveloping countries in Asia (Indonesia 2.2 BOE, Thailand 2.7 BOE,Philippines 2.8 BOE). Annexes I and VII offer detailed historical dataon energy consumption and prices in PNG while Table 2.1 shows consumptiontrends in PNG during 1970-80.

Table 2.1

Primary Energy Consumption, 1970-1980

Consumption (O000 TOE) 1970 1975 1980

Commercial 269 567 709Non-commercial (woodfuel) 343 389 434

Total 612 956 1,143

Percentage Share (%)

Commercial 44 59 62Non-commercial (woodfuel) 56 41 38

Total 100 100 100

Energy Intensity 1/

Total Energy/GDP .53 .68 .80Commercial Energy/GDP .23 .28 .50Final Commercial Energy/GDP .19 .27 .33

Average Growth (% p.a.) 1970-75 1975-80 1970-80

Commercial 16.2 4.6 10.2Non-commercial (woodfuel) 2.5 2.2 2.4

Total 9.3 3.6 6.4

1/ Energy intensity is the ratio of energy consumption in TOE to GDP in'000 1977 Kina. GDP estimates in 1977 prices are: 1155 million Kina in1970; 1406 million Kina in 1975; and 1430 million Kina in 1980.

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2.02 While declining as a proportion of total consumption, woodfuelaccounted for an estimated 38% in 1980 as against 41% in 1975 and 56% in2970. In absolute terms, woodfuel consumption grew at 2.4% durin'g theseventies which is close to PNG's population growth rate of 2.3% p.a.

2.03 Commercial energy consumption increased from 44% of total energyconsumption in 1970 to 62% in 1980, i.e. at a growth rate of 10.2%.Since 87% of all commercial energy consumed comes from petroleum (therest being supplied by hydro) this in turn reflects an increaseddependence on oil imports. Petroleum consumption for power generationhas increased from 18,000 TOE in 1970 (30% of electricity) to 248,000 TOEin 1980 (76% of electricity), i.e. at a rate of 30% p.a. At the sametime consumption of petroleum products in the transport sector increasedfrom 171,000 TOE in 1970 to 272,000 TOE in 1980, i.e. at the rate of 5%p.a. while kerosene consumption, mainly by households, grew from 9,000TOE to 11,000 TOE.

2.04 GDP grew from 1155 million Kina in 1970 (1977 prices) to anestimated 1430 million Kina in 1980, i.e. at 2.2% p.a. (whereaspopulation grew at 2.3%), and per capita GDP therefore stagnated duringthe decade. Despite this, energy consumption has continued to growfaster and the ratio between energy consumption and GDP has thereforeincreased, making PNG more energy intensive.

2.05 The most dramatic increase in energy consumption occurred in1970-75 when the Bougainville Copper Mine (BCL) started production. BCLimports oil to generate electricity which is used primarily to produceconcentrate from low grade ore. Table 2.2 shows the sectoral consumptionof primary commercial energy including and excluding BCL, which consumesa third of primary commercial energy.

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Table 2.2

Shares of Primary Energy Consumption a/(Percentages)

1970 1975 1980

A. Including BCL

Transport 64 38 39(air) (18) (8) (8)

Industry 22 51 47Mining (BCL) (0) (36) (35)Other Industry (22) (15) (12)

Others (Households, commerce) 12 11 14

Total 100 100 100

B. Excluding BCL

Transport 64 59 59(air) (18) (12) (12)

Industry 24 23 19Others (Households, commerce) 12 18 22

Total 100 100 100

a/ Allocating inputs to electricity to end use consuming sectors.

2.06 The increasing intensity of energy use also reflects greaterconsumption of electricity and kerosene in households, and of fuel forelectricity and transport. (For a discussion of the development andorganization of the electric power sector, see Annex II). This takesplace mainly in urban enclaves (such as Port Moresby and Lae) byexpatriates and by the indigenous middle income class whose life-style

follows the expatriate model. 1/ The growth in public employment hasencouraged rural to urban migration and has generated a rapid growth inurban population (7.5% p.a.). This has also led to higher energyconsumption per capita, while the growing penetration of roads into therural areas has led to a growth in energy used in transport.

1/ It is estimated that 59% of domestic electricity consumption in PortMoresby in 1980 is consumed by 3,400 expatriate households, while 52% ofcars and station wagons in 1978 belonged to expatriates.

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The 1980 Energy Balance

2.07 The 1980 energy balance, including woodfuel consumption, isgiven in Annex I (Tables 1.4 and I.5) and is summarized in Table 2.3below. Of the total primary energy consumed, 524,000 TOE or 46% wasindigenous and the remaining 619,000 TOE or 54% was imported petroleum.83% of the indigenous energy production was woodfuel and the remainderwas hydroelectricity. Nearly 90% of the woodfuel was used by households,and the remaining 10% was used in industry.

Table 2.3 1/

Final 2/ Energy Consumption Pattern in PNG in 1980('000 tonnes of oil equivalent)

Electricity Petroleum 3/ Woodfuel 4/ Total

Households 10 18 386 414Industry 80 73 48 201Transport - 275 - 275Others (Agr. & Commerce) 12 5 17

Total 102 371 434 907

1/ Annex I (Tables I.4 and 1.5) contains data on primary energyconsumed.2/ Net of transformation losses of 236,000 TOE.3/ Does not include petroleum products used for power generationequivalent to 248,000 TOE, included in the electricity produced.4/ Estimated.

Sectoral Pattern of Energy Consumption

Transport

2.08 Estimates of consumption of fuel in the transport sector and itsgrowth are given in Table 2.4.

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Table 2.4

Transport Fuel Consumption(000 TOE)

Vehicle 1/ Gasoline Distillate 2/ TotalRegistration (Road & Marine)

OOOKL OOOTOE OOOKL OOOTOE OOOKL OOOTOE

1970 34,667 76 58 75 63 151 1211971 36,163 91 70 111 93 202 1631975 41,430 113 88 100 84 213 1721980 47,436 (1979) 117 90 148 125 265 215

1/ Data from PNG Statistical Bulletin, March 25, 1981. These membersinclude motorcycles and tractors also. The figures for 1971 and 1980excluding these two categories are 33,420 and 42,865 respectively2/ Estimated as a residual after deducting fuel consumption in powergeneration and industry.

2.09 The growth rate of vehicle population excluding motorcycles andtractors has been around 4% between 1971 and 1980, whereas the transportfuel consumption has grown at only 3%. These estimates suggest that fuelconsumption per vehicle has been falling over time, a response both tosteeply increased gasoline prices and introduction of smaller, more-efficient cars. This ratio might have declined further were it not thatmaintenance and depreciation costs are relatively much higher than fuelcosts 1/. Figures for distillate consumption (84% of which is assumed tobe used for road transport) show the same pattern of decline in fuelconsumption per vehicle, although the effect has been less markedprobably because trucking demand is generally less price elastic thanpersonal travel demand. Further discussion of the transport sectorappears in Annex III.

2.10 Although transport is the major user of petroleum products, itis the sector for which there are the fewest alternative non-oil basedfuels. It is also the sector in which demand is likely to increasebecause of increasing urbanization and rural development.

Industry

2.11 The largest single fuel using industry is Bougainville Copper

1/ Some evidence for this is provided by the high attrition rate ofvehicles and their short life. On average, it appears that cars lastonly about 4 years and hence deteriorate at twice or more the rate commonin industrialized countries.

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Ltd. (BCL) which in 1980 consumed 35% of total primary commercial energyand 40% of the petroleum products in the country. The non-miningindustrial sector can be conveniently divided into two; the processing ofagricultural products, and a heterogeneous collection of otherindustries. Of the 155,000 TOE final commercial energy consumption inthe industrial sector (Table 2.3) BCL consumes 101,000 TOE (65%), whileagricultural processing companies and the other non-mining industriesconsume the other 35%. These three subsectors are discussed below.

Bougainville Copper, Ltd.

2.12 In 1979 and 1980 BCL consumed 35% of total primary commercialenergy and 40% of petroleum products (by thermal content). Most of thisfuel was residual fuel oil used in power generation, though appreciablequantities of distillate were consumed by mobile mining equipment andsome diesel was used for drying the concentrate (1.5 million litresp.a.).

2.13 Currently some 100,000 tons of ore per day are crushed, andanother 100,000 tons are moved but discarded. As the ore grade declinescopper production can only be maintained by increasing the volume of orehandled. As the ore volume increases, more ball mills are required, andthis in turn generates further demands for electricity. In 1979 and 1980the maximum demand was 109 MW; this is forecast to grow to 159 MW by1984. Current generating capacity is 135 MW (3 x 45 MW) residual fueloil fired thermal generators, which will not be adequate to meet theexpected growth in demand. Two major studies of the options forelectricity generation done for BCL (by Bechtel and Minenco Pty.) havebeen completed, both of them recommending a shift to coal fired thermalplants. However, BCL's management has decided instead to install two gasturbines with a combined capacity of 45 MW for peaking, to becommissioned in 1982, as a stop-gap while decisions on hydro power, andthe possible switch to coal firing or new coal-fired generating plant,are made. Negotiations between the mine and the governments (local andnational) on extending the mining license are still not finalized and BCLmanagement is in a "wait-and-see" state of mind.

2.14 Although the hydro option is limited to run-of-river 1/ with alow flow of 20 MW, and maximum flow of 60 MW, this alternative isattractive to BCL if financed by the Government. However, it would entailcontinued dependence on fuel oil (or coal, if a switch is made) for thebalance of the power generation. Coal import prices are $35-48/tonne (or$54-$73/tonne of oil equivalent), substantially below the import price ofresidual fuel oil in 1981 ($220-$243/tonne of oil equivalent c.i.f.)2/.

1/ A dam could possibly be built, but requires further investigation.2/ Coal import prices f.a.s. Loloho (the site of the generating station)were estimated at K32/tonne by Bechtel (and perhaps as low as K24) in1981, based on an Australian East Coast price of K19-22/tonne andshipping costs of K6-9/tonne in 25,000 dwt ships or K4.6-6/tonne in50,000 dwt ships, and an exchange rate of $1.5 per Kina.

I - 21 -

Given BCL's objective of increasing copper production, the missionrecommends that the decision to switch from oil should be expedited, andwork advanced on evaluating the possibilities of using a medium-sizedhydroplant or of converting existing BCL thermal plant from oil to coal.

Non-Mining Industries

2.15 Data on all non-mining industries are rather meager; however,the Bureau of Statistics has published data on expenditure on power, fueland light for manufacturing industry for 1978(see Table 2.5) 1/.

Table 2.5Values of Output and Cost of Power, Fuel and Light 1978

Cost of Power, Value of EnergyFuel & Light Output Intensity(K million) (K million) (Percent)

Sectoral Breakdown

Food, drink, tobacco 3.8 184.1 2.1Wood 2.0 45.5 4.4Basic metals 2.8 60.1 4.7Other 3.2 80.4 4.0

Total 11.8 370.0 3.2

Regional Breakdown

South 2.9 92.1 3.1Highlands 1.6 60.7 2.6Morobe a/ 2.2 98.3 2.3Other 5.1 118.9 4.3

Total 11.8 370.0 3.2

a/ Includes Lae.

Source: Bureau of Statistics, Secondary Industry-, 1978.

1/ Data for other years are aggregated with the very energy-intensiveelectricity, gas and water sectors.

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Using a weighted average cost of fuel for 1978, the mission estimatedthat total fuel use in manufacturing in 1978 was 51,000 TOE which isclose to the 49,000 TOE estimated by EPU for commercial fuel use by theindustrial sector (excluding BCL) in 1976/1977. This also constitutesonly about 10% of total commercial energy consumption.

Agricultural Processing Industries

2.16 Energy costs are quite important for agricultural processingindustries for two reasons. Firstly, as these are export industries,they are more cost sensitive than non-traded products because offluctuations in primary commodity prices. Second, they are often quiteenergy intensive. As a result, they have undertaken more substitutionaway from oil to burning wood than other sectors. Table 2.6 summarizesthe importance of each crop for the balance of payments, the proportionof its f.o.b. value accounted for by oil costs where oil is used, and thetotal estimated quantity of fuels used. From this table it can be seenthat oil accounted for 25% of the total energy used for all crop dryingand amounted to 38% on an oil equivalent basis. At current oil prices ithas become commercially attractive to replace oil by biomass - wood,coffee and copra husks, etc., and the share of oil in total fuel use isexpected to continue to fall. This is definitely a very impressiveexample of inter-fuel substitution taking place in response to pricefactors. It is also seen that the burden of fuel costs varies from cropto crop, from a very low 1.2% in coffee processing to 38% for tobaccodried in small barns with kerosene.

Table 2.6

Fuel Use in Agricultural Processing Industriesand Cost Relative to Value, 1980

Exports Fuel costs as Energy Use ('000 TOE)Volume Value % of 1980 Oil Biomass

('000 tonnes) (million Kina) Export Value a/ oil thermal(%) displaced b/ content c/

Coffee 51.0 118.7 1.2 1.5 3.9 7.1Cocoa 28.7 48.4 5 2.3 5.3 10.6Copra 91.6 24.7 15 2.5 9.8 18.6Tea 7.9 8.5 10 1.4 1.4 4.5Rubber 4.0 3.8 .. - 2.0 4.0Tobacco 0.1 0.2 15-38 1.8 0 0Coconut oil 33.6 14.9 5 2.5 0 0Timber products n.a. 47.7 2 3.7 3.0 3.00

Total 264.9 4.3 15.7 25.4 47.8

a/ Cost of oil where used as % of f.o.b. value.b/ Thermal content of oil displaced by biomass.T/ Thermal content of biomass actually used.

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Other Industries

2.17 Between 1979 and 1980 there has been a considerable fall in

heavy fuel oil demand, and some switch to woodfuel. Estimated oilconsumption in industries other than agricultural processing in 1980 isabout 22,000 TOE. Consumption figures and patterns in the totalindustrial sector (excluding BCL) make it clear that most industry in PNGis not very energy intensive, with energy costs amounting to 3.2% ofgross output (Table 2.5) or about 6.4% of value added. This compareswith energy costs in 1978 in BCL of 7.7% of gross output, or about 12% ofvalue added, and energy costs in agricultural processing of 4.3% of grossoutput (Table 2.6).

Agriculture

2.18 Agriculture accounts for about one third of GDP, but a very

small fraction of total energy use. Its direct demand for commercialfuel is estimated at only 3,000 TOE in 1980, less than 1% of total finalcommercial energy consumption. This estimate is based on the smallnumber of tractors in the country (1700), many of which are used for non-agricultural purposes. The processing of agricultural products is, incontrast, quite energy intensive and has already been dealt with above(para. 2.16); agricultural products also require transport, so thatindirect energy consumption use is considerably higher. Althoughagricultural output stagnated in the 1970's, it is forecast to grow atabout 3.5% p.a. during the 1980's. On this basis, tractor usage isprojected to increase, but direct energy consumption remains very small.

Households

2.19 As noted earlier (para. 1.03), PNG is characterized by the

'enclave' type of development, where the urban enclaves account fornearly all the commercial energy consumption and the rural areas arelargely dependent on non-commercial energy. As can be seen from Annex I,total energy consumption in the household sector in 1980 is estimated at416,000 TOE, of which 386,000 TOE (93%) is from non-commercial sources,mainly woodfuel, and only 28,000 TOE (7%) is from commercial sources.Petroleum products (mainly kerosene) account for 18,000 TOE andelectricity for 10,000 TOE of the commercial energy used in households.The rural population is estimated at 2.6 million (87% of total) and itconsumes 371,000 TOE (363,000 TOE non-commercial and 8,000 TOEcommercial). The urban population at 0.4 million (13%), consumes 45,000TOE (25,000 TOE non-commercial and 21,000 TOE commercial). Per capitaconsumption of total energy in the rural areas is therefore estimated at0.14 TOE per annum, while in the urban areas it is lower, at 0.11 TOE perannum reflecting the greater efficiency of use in the urban sector whichrelies on commercial fuels to a greater extent than the rural sector.Hlowever, per capita consumption of commercial energy in the rural sectoris only 3 kgs of oil equivalent per annum as against nearly 50 kgs of oil

equivalent per annum in the urban sector. Presumably all cooking in therural sector is done with woodfuel and the small amount of commercialenergy used is in the form of kerosene for lighting. The per householdconsumption of fuelwood comes to approximately 6.6 kgs per day

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and this is close to the figure for other developing countries (such asIndonesia where 6 kgs per household per day is consumed in ruralareas). In the urban sector, kerosene, electricity and woodfuel are usedfor cooking and electricity and kerosene are used for lighting.

2.20 The household consumption of kerosene for lighting in the ruralareas comes to nearly 22.5 litres/year which is substantially lower thanthe household consumption in middle income developing countries andclosely approximates the level of consumption in the poorer developingcountries. This is one of the reasons why rural electrification programsare not likely to be viable in the rural areas of PNG unless they arecombined with the introduction of productive industries.

Energy Pricing, Taxes and Subsidies

Electricity

2.21 No change was permitted in electricity tariffs from 1975 until1980, despite the increase in cost of fuel by nearly 100% and operatingexpenses by 50%, a major factor which has led to ELCOM's recent financialdifficulties. A tariff study funded by the Asian Development Bank (ADB)was received in 1981 and tariffs were raised three times during theperiod November 1980 - November 1981 by a total of 69%. Table 2.7 showstariffs effective as of January 1, 1982.

Table 2.7

Tariffs Effective from January 1, 1982(toea per kWh)

t/kWh USQ/kWh

(a) Category IPort Moresby, Ramu, Kieta/ArawaAll kWh 11.5 17.25

(b) Category II 1/First 50 kWh 11.5 17.25Balance 15.7 23.55

(c) Category III 2/First 50 kWh 11.5 17.25Balance 26.0 39.00

Minimum monthly charge K 2.00 (US$3.00)

1/ Category II refers to small financially self-sustaining, networks(Annex II).2/ Category III refers to very small ELCOM stations (Annex II).

2.22 The present tariff structure together with the introduction ofthe new gas turbine ensure that ELCOM will not have financial deficits

--25 -

even when the gas turbines are run on base load. Table 2.8 shows howproduction costs are expected to decline with the installation of the newmore efficient gas turbine in Port Moresby:

Table 2.8

Elcom Production and Supply Costs, 1981

Specific Efficiency 1981 Operating Costs (t/kWh)Fuel cons. (%) Fuel Cost System Delivered(litre/kWh) (t/ltr.) Fuel Other Loss (x) Cost

Port MoresbyOld Gas Turbine 0.44 23 24 10.6 2.1 (13) 14.6New (1982) G.T. 0.29 35 24 7.0 2.1 (13) 10.5

Other Large Centers(diesel) a/ 0.30 34 25.1 7.5 5.3 (13) 14.7

Small Centers(diesel) 0.31 33 31.0 9.6 8.4 (19) 22.2

a! Based on Lae, Wewak, Rabaul/Kerevat.

Source: ELCOM.

However, there is a considerable out-cry against the sudden sharpincrease in tariff levels, coupled with increasing complaints about thequality of service. Commercial and industrial consumers are, therefore,increasingly tending to provide their own diesel generation. The highelectricity tariffs are necessary to offset ELCOM's high operating costswhich have resulted partly from increased reliance on imported oil.Therefore, it is essential that other, less expensive, fuels be utilizedfor power generation, before any further cost escalations lead to tariffincreases.

Petroleum Products

2.23 In the recent past the Government has subsidized motor spirit,distillate, and lighting kerosene in remote areas, ensuring that priceswere no higher than 12 toea/litre above main port prices in 1977/78, andsomewhat higher in later years (16 toea/litre in 1981). The cost of thissubsidy scheme was estimated at K1.6 million for 1977/78, and possibly asimilar amount in 1979/80. In the General Price (Amendment No. 64) Orderof November 3, 1981, the maximum selling prices were further raised sothat subsidies were only payable at a few very isolated locations (mainlyin West Sepik). Prices are revised on a monthly basis, on the basis ofsubmissions made by the distributing companies (BP, Shell and Mobil) tothe Ministry of Finance. Table 2.9 shows maximum selling prices forpetroleum products as of November 1981.

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Table 2.9

Maximum Selling Price of Petroleum Products as of November 1981

Motor Spirit Distillate Kerosenet/litre US$ gallon t/litre US$ gallon t/litre US$ gallon

a) Retail price in PortMoresby 36.8 2.09 32.9 1.87 31.0 1.76

b) Maximum price inland(a+16t) 52.8 3.00 48.9 2.77 47.0 2.66

c) Estimated maximuminland price with-out subsidy 91.2 5.47 94 5.64 99.2 5.95

2.24 While the previous, more generous subsidies reflected theGovernment's redistributive and egalitarian aims, they were financiallyburdensome. The present policy reflects the new awareness of theimportance of efficient rather than equitable pricing, a principle alsoextended to electricity pricing. The most important remaining subsidy isthat accorded to ethanol 1/, which, at the proposed Baiyer River Plant,would escape the import dufty on gasoline, yet sell at the post-tax inlandgasoline price. At best, this subsidy should be regarded as a subsidyfor research and development, to ascertain the viability of an ethanolindustry in the Highlands, which the project may produce. As such, itwould be inappropriate to extend the subsidy to other ethanol projects.

2.25 The tax on fuel oil consumption falls mainly on BCL. As it is,since BCL is taxed at the margin at 70%, only 30% of this fuel oil taxfalls on shareholders.

2.26 Kerosene, which is used mainly for lighting, is also taxed,though the tax is small relative to the massive mark-up between bulkretail (at service stations) and local markets. In the recent Budget,taxes on distillates were increased while there was no increase in taxeson kerosene. The mission considers that it is necessary to preserve someconsistency in the taxes on distillate and kerosene to preventinefficient substitution between them.

2.27 In conclusion, the current pricing and tax policies for oilproducts appears to be consistent with other energy policies, and recentchanges made in the 1982 Budget have increased the emphasis placed onefficiency in pricing.

1/ No ethanol is currently produced in PNG, yet this subsidy is intendedto promote ethanol production.

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CHAPTER III

ENERGY RESOURCES: ISSUES AND OPTIONS

Resource Overview

3.01 Papua New Guinea is well endowed with diversified energyresources. The largest resource is the hydroelectric potential createdby the mountainous topography and generally heavy rainfall, particularlyon the Fly, Purari, and Kirori rivers flowing into the Gulf of Papua andthe Musa river flowing into the Oro Bay (See Map 16281). The total hydropotential is estimated at 14,000-21,000 MW 1/ (or nearly 5 to 7 kw on aper capita basis, one of the highest for any country in the world).Moderate size gas discoveries have been made, both onshore and offshore,with gas reserves conservatively estimated at 1.5 - 5.0 TCF andcondensates at over 60 million barrels. However, considering the largearea underlain by sedimentary rocks with potential for petroleum andnatural gas, past exploration has been quite modest and these hydrocarbonresources are essentially unevaluated. Oil companies have notaccelerated their drilling nor has the government induced them to do sountil recently. PNG also has a large biomass potential from itsextensive forests, which cover nearly 40 million hectares, of which lessthan 10% are being used for logging operations. The country has surfacemanifestation of geothermal energy. Coal occurrences have been reportedin the Gulf Province and near Lae. The country's resource base providesa wide variety of long-term options for its energy planners. These arediscussed in the following sections.

Electricity

3.02 The public power sector is in a state of disarray and at presentthere is only limited prospect for improvement. The situation isattributed to weak management, poor planning and poor operations andmaintenance. The large increase in oil prices and the series of problemsstemming from unexpectedly poor hydrological conditions affecting thehydro plants have accentuated the problems.

3.03 ELCOM and its consultant, Charles T. Main, agree on a probableload growth averaging approximately 7% up to the year 2000. Given thecountry's current stage of development and its potential for furtherdevelopment, 7% at first sight appears low; however, the followingfactors would suggest it may not be so: (i) no acceleration of GNP growthis anticipated; (ii) tariffs have become very high in absolute terms, tothe point that they will likely inhibit demand growth in the householdand industrial sectors;(iii) a considerable number of commercial andindustrial consumers have installed their own generating facilities,because of ELCOM's unreliable service and load shedding, and others maydo so 1/; (iv) new mining loads of any large size are not included in the

1/ Installed hydro capacity in PNG is about 100 MW.

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forecast since they will also have captive plants.

3.04 Although there are many potential hydroelectric sites (AnnexIV), the fragmented nature of the country, and limited demand in any onelocality, mean that the development of large hydro resources is onlypossible if it is to support power intensive industry, mainlymetallurgical. This is likely, although not during the eighties due tothe long lead times required by such ventures. Several American andJapanese aluminum companies have shown interest in utilizing PNG's hydroresources.

3.05 A particular difficulty in planning hydro development is thelack of stream gauging records, particularly for the small rivers. Thelarge rivers have been given more attention and gauging information isavailable or, in some cases, is in the process of being obtained. Someidentification surveys of potential small hydro sites have been madeemploying elevations based on profiles obtained from air photography, theformula developed by ADB based on average rainfall and head, and ahelicopter sweep/land touchdown of site. The reports for some of thesesurveys include a preliminary plan for each station identified togetherwith river flow characteristics. This gives a false authenticity toinformation that is highly uncertain.

3.06 Hydro plants installed on such a basis may not meetexpectations, and minimum and average flows may be seriously below theamounts designed for, particularly in dry years. The provision of suchfacilities carries with it the implicit premise that thermal back-up isrequired and in general, that thermal capacity may have to provide muchof the energy, perhaps the bulk, representing the difference between theplant factor of the hydro stations and the system load factor.

3.07 Both ELCOM hydro stations under construction, Pauanda andWarangoi (para. 3.08), fit this profile as there were no river gaugingrecords for either. For Warangoi, which is a very high unit costproject, it is recognized that supplementary diesel will be necessary andit is still not known how much diesel energy on average will have to begenerated annually. The mini-hydro stations (Tinputz, etc.) also lackedgauging records. For the Naoro-Brown potential development there is a 23year gauging record, but located below the junction of the two rivers.For the Tua and Oreba sites, present gauging information is 3 years forone, about 13 years for the other. Rouna had a 23 year gauging record,but actual experience suggests the data may have been unreliable, orsimply that for watersheds of its small size, in such mountainousterrain, gauging records are not as reliable for predicting hydrologicalperformance as they are for larger rivers. There is also doubt that thehydrology of Ramu river in the north (6 year gauging record) would beadequate to support the five unit plant for which it was designed (threeunits have already been installed). Therefore, the mission strongly

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recommends investment in about 75 gauging stations on small rivers (witha potential of 10-15 MW each) throughout the country.

3.08 The 1980-90 development program of ELCOM has been in a continualstate of flux for the past 3-4 years. Several major projects of longstanding have been dropped and others delayed as perceptions changed.The present status is:

(i) Pauanda hydro (12 MW) on the Ramu system is under

construction for commissioning in 1984;

(ii) Warangoi hydro (10 MW) on the Rabaul system is under

construction for commissioning in 1983;

(iii) Rouna 4 (13.5 MW) for Port Moresby is in principle

committed -- provided the investigation underwayconcludes that the stability of the left bank, on whichthe. flume would be built, is, or can be made,satisfactory.

(iv) For Port Moresby, consultants have recently identifiedthe 42 MW Naoro-Brown river site. A feasibility studyfor the Brown River Basin has been commissioned by ELCOM.

3.09 As to the option of using gas for electricity generation for theRamu system, ELCOM hopes to have the Barikewa natural gas field in theSouthern Highlands developed, gas piped about 6 km.to a gas turbine set,and a 160 km transmission line built to the Ramu grid at Mt. Hagen.Very preliminary cost estimates, including an 18 MW gas turbine, areabout K 23 million (US$34 million). Part of the transmission line wouldbe through very rugged country with only helicopter access forconstruction. The precise economics of the scheme would depend on thewell-head price of gas 1/. This is an option that should be evaluatedirrespective of the results of Barikewa 2 as the gas reserves requiredfor supporting power generation for meeting domestic needs are modest -less than 0.05 TCF.

3.10 The gas scheme would be preferable to more hydro plants becauseit would provide firm base load, which could be increased as required byadditional gas turbine installations at Barikewa. All of the four hydroschemes listed in para. 3.08 are run-of-river with firm plant factorslikely to be well below the systems energy needs. Their addition willincrease the imbalance between the energy required and that generated ona firm basis, particularly in dry years to which these streams are sovulnerable. This applies to both the Port Moresby and the Ramu systems,

1/ In Australia, for example, the well head price of gas varies from

KO.4 to K1.25 per 1000 cubic feet of gas (the equivalent of US$33/BOEwould be K3.5/1000 cubic feet).

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until they are provided with a substantial base load generating plant.The Pasca gas/condensate discovery some years back, located 80 km off-shore in the Gulf of Papua and 250 km up the coast northwest of PortMoresby, might, if exploited quickly, provide thermal generation to thePort Moresby area. A brief desk study by the World Bank's EnergyDepartment indicates that the economics of such an undertaking might bequite favorable yielding an economic rate of return of 20%. Theeconomics of such a project are further improved by the production andexport of methanol.

3.11 In any case, cheap baseload power facilities are needed as soonas possible. Therefore, ELCOM should pursue the possibility ofinstalling a coal fired conventional steam thermal station. The logical

size would be about 25 MWl/. If the unit cost is less than $1500/kw,then the cost per kWh of burning imported coal would be substantiallylower than the hydro in prospect, and would provide base load. Evenlarger units of standard size might well be economic, although theadditional capacity could be somewhat premature. The main point is thatthe two major systems, i.e. Port Moresby and Ramu, have to be relieved ofthe necessity of continuing to burn high cost distillates in dieselengines and gas turbines in increasing amounts in the future, due tohydrological uncertainties associated with small run-of-river hydrostations.

3.12 The gasification of woodfuels in large gasifiers suitable fordirect use in gas turbines is still in the development stage; therefore,the possibility of gasifying sawmill wastes at Lae or elsewhere on asizeable scale will have to wait. However, plans to use the gasificationprocess to fuel small diesels (up to 500 kw) maybe pursued as technologyfor this purpose is adequately developed. The sawmill wastes could alsobe used for thermal power generation using specially-designed boilers

3.13 The Government s cautious approach to rural electrification andmini-hydro seems reasonable. It appears that photo-voltaic cells mightcome to have limited commercial application, predominantly fortelecommunication but also possibly for lighting in villages, and in someother places for fans and pumps where the consumers are affluent. Theoutlook for wind generated power, however, does not appear promising onthe basis of available meteorological data.

3.14 Besides Ok Tedi located in the westernmost part of the NewGuinea Island near the Indonesia border which is being developed for goldand copper concentrates, based mainly on hydro power, other sites whichmight offer opportunities for similar, industrial and mining developmentinclude: (a) hydro sites on the Purari River mainly for a metallurgicalenclave such as aluminum smelting; (b) the Kaugel River in the north for

1/ Since the return of the mission it has been learnt that a 25 MWthermal station is under construction in India at an estimated cost of$1000/kw. It is understood that other countries such as Poland, E.Germany and France also manufacture standard sets in this range.

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nickel and cobalt mining, and (c) Porgera in Enga Province for goldmining. None of these potential developments are firm prospects at thisstage. If one or more should eventually proceed, it may supply power toELCOM. This might be of importance to the process of converting ELCOM'ssystems to a larger network, thus providing economies of scale. Aninventory of all large hydro sites (over 50 MW) should be compiled andpreliminary feasibility studies should be carried out on 3-4 sitesselected from this list. Current work on a metallurgical resourceinventory should be continued in parallel.

3.15 The Government is to be commended on its program for conser-vation of electricity, that is, the substitution of solar for hot waterheating. This is proving successful and is reducing ELCOM's peak andenergy demand by a substantial amount (para. 3.40).

3.16 To supplement its current planning work, ELCOM should draw up aplan for least cost development of the power sector over a longer timeframe of 15-20 years. In order to do this, however, studies onutilization of on-shore/off-shore gas fields, the setting up of thermalstations at Port Moresby based on coal, and at Lae based on wood-wastes/coal and the feasibility of large hydro sites, should be completedas a matter of priority.

Oil and Gas 1/

3.17 A significant amount of exploration work has been performed inthe oil and gas subsector over the past fifty years, particularly since1958 when the Petroleum Subsidy Act (PSA) was passed by the CommonwealthGovernment of Australia. Under the PSA, a subsidy of 50% was availablefor all approved projects, including geological and geophysical surveysand drilling of wells. All data collected under these approved projects,including samples and cores and copies of all documents had to beprovided to the Government. Under this arrangement, 28 wells weredrilled, and 150 geophysical and geological surveys were completed 2/.In addition 30 wells were drilled prior to 1954, though very littleinformation is available on these operations. About 30 wells were alsodrilled by private companies at their expense and partial data areavailable on them. Nearly 40,000 kms of seismic work has been done todate, of which nearly 30,000 kms are in the offshore areas and 10,000 kmsin the onshore areas. Most of the offshore data were collected during

1/ This report does not discuss the feasibility of a refinery which wasproposed in 1979 for PNG since the recent report on this feasibility (OilSupply Options Study, RPT Economics Studies Group of London, January,1981) showed that there was no justification for a refinery untildomestic oil discoveries had been proven. The mission concurs with thisconclusion.21 Robertson Research Consultants have reviewed and catalogued all thework done up to date under the first phase of a World Bank aided projectand its report has been recently circulated.

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1968-74 period. A complete set of this data is in the GovernmentArchives at Canberra, and will become available to PNG on request. Thesecond phase of the current petroleum exloration promotion project, whichthe Bank is financing, will be partly used to build up within theGeological Survey Division expertise in petroleum matters (generallyreferred to as Petroleum Resource Assessment Group or PRAG) and toprovide for storage and documentation of all available materials in PNG.

3.18 There are three major basins in PNG; namely, (i) The PapuanBasin; (ii) The North New Guinea Basin; (iii) The Cape Vogel Basin andother minor basins in the smaller islands (Map 16281). The Papuan Basinis by far the largest (250,000 sq. kms) and contains most of the wellsdrilled. There have been six reported discoveries there: two offshore,namely Pasca and Uramu, and four onshore in the Gulf Province, namelyPuri, Barikewa, lehi, Bwata 1/. Indicated gas reserves are estimated tobe 1.5-5.0 trillion cubic feet (TCF); the wide range of estimates resultsfrom the fact that very little follow-up drilling has taken place aroundthe discoveries. At Pasca, the confirmation well had a gas flow at anestimated rate of 17 million CFD, with a significant quantity ofcondensates. The condensate reserve is estimated to be around 60 millionbarrels. However, the field is located in water depths of around 300feet and may prove to be expensive to develop. Uramu gas field is inshallower water (30 feet) and therefore its exploitation may be moreeconomic. The discovery well had a gas flow at 13-14 million CFD, andreserves are estimated at 0.2-0.4 TCF. However, the gas is dry andcondensate reserves would be minimal.

3.19 The onshore discoveries are also prospective, the largest ofwhich appears to be Barikewa, where the gas reserves have been estimatedat 0.5-1.5 TCF. Drilling of the first delineation well is in progress.Iehi appears to be the next best discovery, although no confirmationwells have been drilled. Bwata, and Puri are much more complex prospectsand are likely to be smaller. The North New Guinea Basin covers about athird of the area of the Papuan Basin. Prospects here are less exploredthan in the Gulf area and no discovery has been made to date, althoughoil and gas shows have been noted both at the surface and in wells. Someexploration work is in progress. In the Cape Vogel Basin and the smallerbasins associated with the island margin very little work has been doneto date. The gas discoveries in the offshore and onshore areas of thePapuan Basin are not yet large enough to consider export potential, e.g.LNG; however, they should be adequate for the purpose of meeting domesticneeds for power generation for a very long time 2/. In part, the presentdilemma is that these discoveries are not large enough for energy exportson a long term basis, and that the domestic demand is not large enough to

1/ There has been a minor discovery at Kuru, which has not been fullytested.2/ One TCF could support gas production rate in excess of 120 millioncubic feet/day (MMCFD) - roughly the heating equivalent of 1 million tonsper annum of fuel oil.

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exploit these resources solely for domestic consumption 1/. But unlessgas is used for power generation, dependence on imported oil is likely toincrease over time. This is why a number of alternatives need to beexamined whereby gas for power generation and industry becomes availableat Port Moresby and other areas and the export sector ensures thedevelopment of the gas fields and supply of gas for domestic consumptionat reasonable costs.

3.20 The offshore gas fields, Uramu and Pasca, both located in theGulf of Papua may be reviewed first. Two reports 2/, one on reserveestimates and the other on gas utilization, both prepared in 1978, weremade available to the mission. The resource estimates have been made bythe group holding the exploration license, which consists of Superior,Arco, and Sun. The gas utilization study was made by Pace Engineering onbehalf of these companies and covered three possible scenarios: LNGalone, LNG and LPG recovery, and LPG recovery alone. The utilizationstudy was based on the earlier reserve study and all three scenarios (asof 1978) resulted in unacceptable to very marginal economic returns.

3.21 A review of these reports suggests that (a) the recoverablereserve estimates are conservative, and (b) the three scenarios used inthe utilization study do not cover all available options. The reserveestimates are conservative with respect to reservoir volume, i.e.porosity of the reservoir rock and the gas/water contact, liquidproduction potential at Pasca and recoverable fraction of in-placereserves. The earlier preliminary estimate of.l TCF and 60 + millionbarrels condensate recoverable made by several workers for Pasca alone,based on data of Phillips Petroleum, may be more reasonable. Preliminarystudies suggest that at current prices the field may well be economic.Given the gas/condensate ratio of the reservoir, it may be possible toproduce as much as 6,000 barrels per day of light product -- a quantityroughly equal to the current rate of consumption of light distillates. Ifgas reserves of 1 TCF are confirmed, the Pasca field could support a gasproduction rate in excess of 120 million cubic feet per day (MMCFD),roughly double the entire domestic demand for heavy liquid products.This could be utilized for power generation and possibly for methanolproduction.

3.22 There are many possible scenarios for conceptual designdepending on the outcome of further drilling and testing. Some of themare:

(i) Liquids are stripped from the gas and the dry gasreinjected into the reservoir. The stripping could be

1/ Total volume of petroleum products used for electricity generation in1980 is estimated at 247,000 TOE.2/ "Reserve and Deliverability Report of the Pasca and Uramu Fields" and"The Commercial Utilisation of the North Delta Gas Resources in PNG - ARe-evaluation".

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done on the platform with liquids loaded directly to atanker from a single buoy mooring system (SBM). Theliquid products could either be entirely exported or usedpartly as a gasoline substitute or extender. The dry gascould be subsequently produced for domestic use as andwhen required.

(ii) Both liquids and gas would be produced at once with someof the gas sold for domestic consumption and theremainder reinjected to maintain reservoir pressure.This case would require a pipeline to Port Moresby(either entirely offshore or partly offshore and thenonshore).

(iii) In addition to alternative (ii) above, a shore-basedmethanol plant for domestic and export markets could bebuilt.

These alternative scenarios, in addition to the three considered by PaceEngineering, i.e. LNG recovery alone, LNG and LPG recovery, and LPGrecovery alone, are only indicative of the many different optionsavailable for development of the Pasca field and the consequent need foran in-depth gas utilization study which the mission recommends. If itproves possible to develop Pasca, the possibility of developing thenearby offshore Uramu field is enhanced.

3.23 The onshore gas discoveries at Barikewa and Iehi also offerinteresting possibilities for development, the most important being powergeneration with gas turbines at or near the gas field and transmission toMt. Hagen or nearby, for connection to the Ramu grid. The onshore fieldscan be developed by themselves without reference to the offshore fieldsor to export possibilities. One production well may be adequate to meetthe thermal power component of the Ramu grid and could possibly becompleted quickly.

3.24 What emerges, therefore, is that there are many options whichthese offshore and onshore gas discoveries provide, and the missionrecommends that these should be taken into account in drawing up anymedium-to-long-term energy plans. The mission recommends that theGovernment require speedier exploration and appraisal of discoveries bythe oil companies as their work program comes up for periodic reviewunder the terms of the licences already granted.

Coal I/

3.25 Coal occurrences have been discovered in the Morobe and GulfProvinces and near Madang (Map 16281 and Annex V). They have generally

1/ Material in this section is based on the Geological Survey Report"Coal Occurrences in Morobe and Gulf Provinces",, by R. Rogerson, April1981.

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been small deposits of low grade coal with most seams dipping at moderateangles, mainly in rather remote areas, and it is expected that infras-tructure, extraction and transport costs for most of these reserves willbe very high. However, several occurrences seem prospective,especially in Pindiu, Hohoro and Lower Purari:

(i) Pindiu area in the north: Blue Circle Southern CementLtd. has reported a 3 m seam with possible reserves of40-50 million tonnes. The 1980 company report suggeststhe coal is sub-bituminous in rank. Reserve estimateshave since been downgraded.

(ii) Lower Purari and Hohoro areas in the south: Largereserves made these ocurrences prospective except for thefact that the seams dip and the area can become floodedquickly making exploration and mining difficult andexpensive. The characteristics of the Lower Purari coalreserves are set out in Table 3.1 below.

Table 3.1

Lower Purari River Coal Characteristics

Variable ValueSeam Thickness 0.4 - 2.63 m most > lmMoisture 11.8 - 21.6% most 14-17%Volatile Matter 38.6 - 49.6% most 39-43%Ash 2.9 - 14.9% most 3-8%Fixed Carbon 21.0 - 39.7% most 30-38%Specific Energy 14.83 -23.29% MJ/kg 1/ most 20-22 MJ/kgSulphur 0.27 - 4.56% most 0.3-0-5%Moisture Holding Capacity 22.3 - 37.4 most 23-28%Relative Density 1.35 - 1.59 most 1.36-1.45

1/ Equivalent to 3,514 KCal - 5,519 KCal/kg.

3.26 From the meager information available, it is generally agreedthat technically recoverable coal reserves exist in both Morobe and GulfProvinces and that Pindiu, Purari and Hohoro areas seem most pros-pective. The economics of potential open-cut mines in these areas shouldbe closely examined for the purpose of power generation in Lae and Port

Moresby as an alternative to the use of Australian steam coal.L/ Forthis purpose priority should be given to geological exploration of thePindiu area, and technical assistance should be sought for this.

1/ The mission understands that there has been a moratorium on the issueof new mineral production licences because of personnel constraints inthe Division of Mines.

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Geothermal Resources

3.27 Manifestation of volcanic activity can be found in many-parts ofPNG, and considerable geological and geophysical work has been done toidentify geothermal potential since 1950. A substantial part of thiswork has been done on New Britain and D'Entrecasteaux Islands east ofPapua, which are held to be the most prospective. There are surfaceevidences of hydrothermal activity in the form of hot water seeps andgeysers at temperatures of 900-950C, particularly in the Rabaul, Hoskins

and Talasea thermal areas in New Britain and the Deidei and Iamalelethermal areas in the Fergusson Island of the D'Entrecasteaux group.There are no firm estimates of the potential of these areas, but a teamfrom the Geological Survey of New Zealand carried out a preliminaryassessment in 1974 and recommended that further geological andgeophysical work be done 1Y. As the electricity consumption in theseareas (with the possible exception of Rabaul) is small and there islittle or no consumption of steam for process purposes, there is nourgency in developing the potential, but some priority may be given toidentifying the potential of the Rabaul thermal area.

Renewables

3.28 The potential for energy from renewable sources is very large.A substantial part of the land area is under forests, estimated at 40million hectares. Only a small part of this resource is being usedpresently. In addition, agricultural products and wastes could be usedeither directly as an energy source or in the form of biogas orethanol. There is also a high rate of insolation spread over the yearand application of solar energy for heat and electricity becomespossible. However, wind and wave energy are likely to have negligiblepotential. Some of the more important renewables are discussed in thefollowing section.

Woodfuels

3.29 At present, about 1.0 million tonnes of woodfuel are being usedper annum, 95% of which is consumed in the household sector for cookingpurposes. The remaining 5% is used in the industrial sector for dryingand other low grade heat applications, particularly in agriculturalprocessing. Expansion of wood utilization, especially in the industrialand power sectors, has been one of the objectives of energy planners.However, organized and systematic utilization is very difficultconsidering the lack of access roads into forest areas, the very hightransport costs and possible adverse ecological effects. Yet theattraction of readily available wood residues, especially sawmill wasteswhich could easily supply industrial energy, led at first to emphasis oncharcoal production. Charcoal was expected to become a standardindustrial fuel since it is easier to transport than wood, it is storable

1/ "Geothermal Investigations in Papua New Guinea" by G.W. Grindley andL.A. Nairn, August, 1974.

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and can be used in existing equipment with a minimum of modification.Production of charcoal was to be carried out by use of batch operatedkilns working on the larger waste pieces and by means of continuouspyrolysis systems processing the smaller-sized material, a method whichalso produces an oily fraction that can be used as industrial fuel. Thevarious charcoal kilns used did not prove feasible and experimentationwith others is still going on, while the pyrolysis project passed from afeasibility study to the construction of a small pilot plant at theUniversity of Technology at Lae. However, the plant was dismantled inNovember 1981 and moved to the Dylup cocoa/copra plantation near Madang.

3.30 With the demise of the industrial charcoal program, focus wasshifted to gasification of wood wastes from the Lae Sawmills estimated at100,000 tons per annum. At present, there are no industrial scalegasifiers installed, though plans to put a gasifier/burner in the LaeBrewery, in place of the existing oil-fired boiler, are beingimplemented. Wood gasification for running of stationary engines mighthave a greater application since a number of diesel generating sets areoperated all over the country. Many of these are in remote areas whereit is difficult and costly to transport the diesel fuel, and woodfuel isavailable nearby. There is also the possibility of using woodfuel forsteam and power generation in conventionally-fired thermal powerplants. This option has been examined for the Port Moresby area, and ithas been concluded that the available woodfuel resources there cannotsustain a 10-15 MW power plant over the longer term. Such an option maybe feasible in the Lae area where 100,000 tonnes of wood wastes areavailable, which are now disposed of by burning at considerable cost andpollution of surrounding areas. It is recommended that the possibilityof using these wood wastes for steam/thermal power generation be furtherexamined.

3.31 In most of the rural areas, fuelwood is likely to continue to beused for cooking in the households, and the demand for this purpose maybe expected to grow at the same rate as the population. In addition toits possible use as a substitute for diesel in the running of dieselgenerating sets in the remote areas and as a fuel for power generation,there is some evidence of increasing quantities of fuelwood being used inindustry as a source of heat (e.g. for tea drying). These options shouldbe further encouraged and woodfuel should be made readily available atreasonable cost especially to food processing and other non-miningindustries.

Ethanol 1/

3.32 In its "White Paper" of 1979, the Government placed considerableemphasis on the development of ethanol production from biomass tosubstitute for transport fuel. A target of 130 m litres/annum productionby 1990 was given and projects proposed for production of

1/ An internal report on ethanol projects in PNG is being prepared bythe Industry Department of the World Bank.

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ethanol from cassava, sugarcane, molasses and sago palm starch. At thetime of the mission a small (2.0 - 2.5 million litres/annum) cassavabased project was under development in the Highlands at Baiyer River.Government statements have emphasised the intention that ethanolproduction should be competitive in cost with fuel imports and furtherdevelopment of this project is contingent on its economic viability basedon this criteria.

3.33 PNG experiences a fuel deficit and enjoys an agriculturalsurplus. However, this surplus rests largely on tree crop products andthere is no history of commercial production of sugar or cassava. On theother hand, in general there is a reasonably abundant supply ofcultivable land, and the availability of investment funds is a moreimportant constraint than land supply in spite of the complicatedproblems associated with land tenure in PNG. At present, a nationalsugar industry is being created in the Ramu Valley, with an initialtarget output of 30,000 tonnes/annum. Molasses by-product from thisindustry is expected to be the single most promising feedstock forethanol production, in view of its low opportunity cost. At BaiyerRiver, local cassava varieties planted for the ethanol project are givingextemely impressive initial yields (70 tonnes/hectare). Naturally-occurring stands of starch-bearing sago palm (and of the nipa palm whichyields a sucrose - rich sap) are extensive, but collection systems arelikely to prove problematic.

3.34 The economic and financial viability of ethanol production inPNG will be far more location-specific than in most countries, because ofthe unusual lack of geographic integration. As Map PNG 16180illustrates, the national road system and hence the market for motorspirit comprises a series of coastal towns or cities, each with its ownhinterland road system, but only connected to each other by sea or air.The larger coastal towns land refined petroleum products directly frominternational vessels (Port Moresby, Lae, Rabaul, Madang, and Arawa Bayfor Kieta), while smaller ports must rely on domestic coastaltransshipment (e.g., Wewak). The consequence of this fragmentation of analready small national market for gasoline is to add significantly to thebarriers facing any potential ethanol project, since production whichexceeds the absorptive capacity of a small immediate market would have tobear the additional cost of coastal shipping to another region of thecountry.

3.35 As a result of these locational factors, the ethanol plantsunder consideration are mostly very small by world standards and unableto benefit from economies of scale. In addition, PNG's topography,poorly developed infrastructure and shortage of indigenous technical andmanagerial skills greatly increase costs of construction and operation ofethanol plants compared to countries like Brazil. The Baiyer Riverethanol plant (capacity 8-10,000 litres/day) will cost about five timesas much per unit of daily capacity as an optimal scale plant in a 'lowcost' country. This particular project, unlike the others beingconsidered, would benefit from 'natural protection' since gasolineimported to the Highlands must bear heavy transport costs. However, even

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allowing for this factor and writing off over US$2.0 m already spent, theeconomic viability of project continuation would appear marginal at best.

3.36 Apart from production-side difficulties posed by high plantcapital costs and technical uncertainties relating, for example, to theproposed sago palm components, the government's originally publishedethanol targets have been recognized as over-ambitious. Quite apart fromthe technical problems, substitution of ethanol for gasoline in thetransport sector could not absorb more than 30% of the originallyproposed 1990 production (unless heavy subsidies were introduced) 1/, andtechnical problems to substitution for diesel are severe. The governmenthas recognised the problems involved in the original plans and iscontinuing to cut back the ethanol program radically.

3.37 Proposals have been prepared to add an ethanol plant to thesugar mill under construction in the Ramu Valley. Such a plant wouldenjoy a number of advantages unique within PNG. Capital costs for theethanol project would be significantly reduced, especially on the 'frontend', through sharing of facilities with the sugar mill. Much of thefeedstock for the alcohol plant would be by-product molasses, whosealternative export value after deducting transport costs would be verylow. Finally, the project is well placed to serve the sizeable market inthe industrial city of Lae and at least the lower stretches of theHighland Highway, enabling the plant to be built to an intermediatecapacity of 30,000 litres/day (i.e. annual output 6.0 m liters which isabout 5% of annual gasoline consumption in 1980 estimated at 117 millionlitres). A consultant's feasibility study for this project estimates aneconomic rate of return of 18%2/. If this is so, then the Ramu Valleyethanol proposals must be considered economically attractive. Otherprojects, however, are unlikely to prove economically viable unless worldgasoline prices record further significant increases or considerableprogress is made in reducing capital costs of small-scale ethanolplants. Any proposed new ethanol projects must prove their economicviability before further investment in them is made.

Biogas

3.38 Early in its lifetime the EPU facilitated contracts betweenAppropriate Technology International (ATI) and the Lae City Council tobuild a biogas plant operating on night soil and severage, and later itarranged a deal between the PNG Coffee Board and a Waghi Mek (near Mt.Hagen) coffee cooperative to build a small scale demonstration biogasplant operating on the pulp from coffee cherries. The program has hadmixed success, with the coffee project being by far the more promising ofthe two. However, visits to the sites have revealed that both plants arecurrently inoperative for technical reasons. Although biogas is not seenas a major industrial energy source on a national scale, it does offer ameans of producing energy at some sites, especially in remote areas, but

1/ Detailed analysis available in Bank internal report on PNG's ethanolprojects, referred to in footnote page 37.2/ Recent communication of EPU.

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this would necessitate further improvement in the digester design by themanufacturer. However, the mission believes that no additional effort bythe EPU is required to facilitate introduction of this technology whichhas only limited application in PNG for the present.

Mini and Micro-Hydro

3.39 While agreeing that micro-hydro is in principle ideal for smallvillages and rural electrification (RE), EPU notes that in the 5 kw sizeor so, the unit cost is K 3,000-4,000 per installed kw, the unit issubject to fluctuating water availability and silt damage to headworksand turbines and, for firm load, must be supported by diesel whichamortized over 30 years would cost 20-30 toea/kWh. This view, in part,reflects the experience to date with the two of the four mini-hydrostations financed by the Asian Development Bank, (i) Tinputz (200 kw,K 532,000, cost/kw K 2600, cost of energy 16 toeas/kWh) and (ii) LakeHargy (750 kw, K 1,900,000, cost of energy 16 toeas/kWh). In fact theconstruction of these two projects was suspended in April 1981 in view ofthe large cost overruns experienced by the Sohun (commissioned 1980) andRu Creek (commissioning April 1982) mini-hydros, and the indication thatTinputz and Lake Hargy were going to incur large overruns, possibly up to100% of original cost estimates. One of the main advantages of micro-hydro in countries other than PNG is that a substantial, if not all, partof the inputs including rotating machinery can be procured and maintainedlocally. However, no local materials or adequate expertise exists inPNG, and therefore such plants may not be as viable in PNG as in othercountries. (For further discussion of rural electrification see AnnexT I).

Solar Water-Heating

3.40 The Government has underway a highly successful program of

conversion from electric to solar hot water heating. A typicalinstallation, imported from Australia to install or retrofit an existingelectric hot water installation costs about K 700 for a 70 gallon tank.With the current high tariffs, it is expected that it would pay foritself in 2-3 years. In areas where there is a substantial rainy season,back-up electricity water heating is necessary. It is understood thatsolar heating equipment might be manufactured in PNG within a year.

3.41 EPU expects that sometime in 1982/83 some 7000 hot water solarheating units will have been installed. The high rate of installationreflects a response to Government regulations which effectively bannedinstallation of electric hot water heaters in new homes and buildings andprovided tax write-off incentives to retrofit existing electricinstallations. The 7,000 solar installations will result in asubstantial reduction of the electricity peak and energy demand, perhapsas much as 7MW out of total (ELCOM) installed capacity of 167 MWdepending on the coincidence 1/ factor applicable to all electric water

1/ The coincidence factor is the fraction of all electric water heatersin the system that would be switched on simultaneously at any one time.

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heaters in the system and realizing that most locations would requireboosters for the rainy season.

Photo-Voltaic Cells (PVC)

3.42 PVC can be used to provide light or refrigeration or to runwater pumps and fans. At the high cost of K 550 (US$825) for a two lightinstallation in villages isolated from the power network, it isuneconomical. Aside from cost, there is also the equipment reliabilityproblem. PVC is, therefore, more likely to be used for the power supplyof telecommunication equipment or refrigeration of medical supplies inisolated areas. Its broader use for rural electrification is unlikely todevelop not only because of cost, but also because in most ruralhouseholds even the use of kerosene for lighting is negligible (estimatedat about 22 litres per household per annum). However, as the cost ofcells declines in the future with improved technology, these and otherapplications may become more attractive. For this reason the relativelylow level of funding on these projects may continue.

Wind-Electric Generation

3.43 Wind in PNG is comparatively localized. Moreover, windgeneration is fairly complex, and, coupled with the isolation of suchinstallation, would be difficult and very expensive to maintain. It doesnot appear likely therefore to be a factor in the rural electrificationprogram.

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CHAPTER IV

ENERGY OUTLOOK TO 1990

Introduction

4.01 Papua New Guinea has a wealth of natural resources to beexploited, and many of them lend themselves to large enclave developmentswhich, like BCL in the early 1970's, and Ok Tedi in the 1980's, wouldeventually make a substantial impact on the economy and especially onenergy supply and demand. On the supply side the main energy exportingoption would be one based on the already discovered gas fields. Whetherthis would take the form of direct LNG exports, or whether it wouldrequire the processing of gas into methanol or ammonia/urea, will dependon the size of the field, the market prospects of the alternatives, andthe capital requirements for such industries located in PNG. Anotheroption that is being considered is the development of a large hydro basedaluminum smelter (although this is unlikely to materialize during the1980's), which would allow the indirect export of the hydro electricityembodied in the aluminum 1/. This might have the additional advantage ofproviding a surplus of cheap electric power for domestic use, displacingfuel imports. At the moment, all electricity options available arehandicapped by small scale and consequent high costs, but the developmentof large enclave hydro-based industries would break this constraint, atthe same time solving many of the problems of supply reliability.

4.02 The view taken in this forecast is that the aluminum smelter isunlikely to materialize in eight years, partly because market prospectsfor aluminum look poor in the near future, while the hydro schemenecessary for a metallurgical industry would have a substantial leadtime. No new enclave minerals projects are included in the forecast, andso the structure of the economy is assumed essentially unchanged on thedemand side.

Electricity

4.03 Forty percent of all petroleum imports are used for powergeneration, for which there are many substitution options available.Table 4.1 summarizes the forecasts for electricity generation by BCL, OkTedi, the public utility network (ELCOM) and small captive generation.

1/ Several aluminum companies, including American and Japanesecompanies, have shown interest in utilizing these resources.

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Table 4.1

Forecast of Electricity Generation, 1985 and 1990(GWh)

Rate of Growth1980 1985 1990 1980-85 1985-90

(%) (%)

BCL 790 1185 1440 8.4 4.0Ok Tedi - 87 225 - 24.0Elcom 412 857 788 6.2 7.2Others 51 35 49 -7.3 7.0Total 1253 1864 2532 8.3 6.3

4.04 A number of options are available for generating electricity:hydro, indigenous gas, imported oil, and imported coal. Given theIenclave type of development typical of PNG, the three major generatingentities namely, BCL, Ok Tedi and ELCOM may adopt many differentstrategies, depending on the extent of government intervention, theresults of feasibility studies yet to be carried out, and the speed withwhich gas resources are developed. Based on certain assumptionsregarding use of coal and gas, three supply scenarios have been workedout for 1990. For 1985, there are no alternative scenarios due to theshort lead time available although by then BCL may switch to coal-firedthermal plant. The likely option now 1/ is to install 2x45 MW coal-firedsteam generators. The three scenarios envisaged by the mission to supplyelectricity in 1990 are summarized below:

1. Case A (Gas Case): This is the optimistic case whichassumes that Pasca gas field will be developed, that gaswill be piped to Port Moresby for power generation and thecondensates from Pasca will be recovered and exported.Hydro will be developed at BCL, in addition to the coal-fired thermal station mentioned above. Investment costs inthis case, exclusive of a methanol plant, are estimated atabout US$850 million (Table 6.1). A variant to the abovescenario providing for methanol production for export hasalso been considered.

2. Case B (Coal Case): This case assumes that coal will beused for power generation at Port Moresby and BCL would addmore coal-fired plants, all at a total cost of US$555million.

1/ As recommended by consultants to BCL (para. 2.13).

- 44 -

3. Case C (Business as Usual) (BAU): Dependence on fuel oiland distillates for a substantial part of thermal.generationcontinues, and a run-of-river hydro for ELCOM. Investmentin this case would be smallest, at US$430 million.

In all the three cases, Barikewa gas is used for power generation for theRamu grid.

4.05 The break-up of electricity generation by hydro and by thermalfuels for 1985 and for the three supply options for 1990 is given inTable 4.2:

Table 4.2

Break-Up of Electricity Generation in 1985 and 1990(GWh)

1985 1990Case A Case B Case C

Gas Coal BAU

Hydro 345 990 640 790

Thermal

Diesel 495 252 252 272Fuel Oil 1045 - - 1320Gas - 300 130 130Coal - 900 1510 -Total 184 2532 2325 232

4.06 The corresponding fuel inputs required for the differentscenarios is shown in Table 4.3.

- 45 -

Table 4.3

Fuel Inputs Required For Electricity Generation( 000 TOE)

1985 1990A B C

Fuel Gas Coal BAU

Distillates 128 72 72 78

Fuel Oil 264 - - 371

Gas - 99 43 43

Coal _ 304 447 -

Total 392 475 562 492

The Transport Sector

4.07 During the first half of the decade, the mission assumes thatconsumption of fuel in transport is expected to grow at an annual rate ofonly 2% reflecting the effects of a switch to smaller more fuel efficientvehicles and possible reduction in the number of expatriates working inthe country. In the second half of the decade gasoline consumption isforecast to grow at 3% per annum and distillates at 5% per annum. Theserates are slightly higher than those achieved in the past decade, but inthat decade real prices rose 100% and GNP stagnated. In the 1980'sfurther substantial real price rises are less likely, and GNP is forecastto grow more rapidly. Moreover, demand for shipping by Ok Tedi isprojected to build up to 112,000 tonnes per annum by 1990. Air transportis also assumed to grow, and Avtur consumption is projected to grow at 5%per annum while Avgas remains constant.

Industry

4.08 During the 1980's, BCL is projected to handle 4% more ore perannum to offset the decline in ore quality, and possibly increaseconcentrate production. This will increase demand for distillate fueland implies a 1990 consumption of distillates of 51,100 tonnes. Ok Tediwill have reached Stage III by 1990 and is assumed to consume 21,200tonnes of distillate in mining and processing ore, and 7,000 tones offuel oil in copper concentrate drying. Agricultural processing isassumed to continue substituting biomass for oil, thus reducing its

- 46 -

demand for distillates to 4,000 tonnes while biomass demand rises by 3%per annum to 88,000 TOE. Remaining industrial fuel use is assumed togrow at 7% but its composition depends on the relative prices ofalternative fuels. If gas and condensates are available in Port Moresbythere will be some substitution of gas for other fuels.

Other Sectors (Agriculture, Households, etc.)

4.09 Tractor demand for distillate is assumed to rise at 3% per annumreaching 5,200 tonnes by 1990 for the agricultural sector. Keroseneconsumption in the household sector is assumed to grow at 5% per annum to28,000 tonnes by 1990. Urbanization is expected to continue at pastrates. Per capita woodfuel consumption is assumed to remain constant inboth the urban and rural sectors.

4.10 Detailed energy balances for 1985 and 1990 are given in Annex I,Table I.7 shows energy supply without methanol production and export,whereas Table I.8 includes methanol. These two calculations have beenmade to show the effect of methanol production on the import bill (Table4.7). Annex I, Table I.9 corresponds to the coal option while Annex I,Table I.10 reflects the Business-as-Usual scenario. Table 4.4 belowshows forecast final energy consumption pattern for 1985 and 1990 1/.

1/ Annex I, Table 1.11 shows final energy consumption without copper(BCL and Ok Tedi) and exports.

- 47 -

Table 4.4

Forecast Final Energy Consumption Pattern for 1985 and 1990(in -000 TOE)

Electricity Petroleum Woodfuel Total

1985

Households 12 22 430 464Industry 126 93 - 219Transport - 297 - 297Others (Agr. and Commerce) 15 8 70 93Total 153 4201/ 500 1073

1990

Households 17 28 473 518Industry 172 122 - 294Transport 20 367 - 367Others (Agr. and Commerce) 20 9 88 117Total 209 526_/ 561 1296

Growth Rates (%) 3/

1980-85 8.5 2.5 2.9 3.41985-90 6.4 4.6 2.3 3.91980-90 7.4 3.6 2.6 3.6

1/ Does not include 392,000 TOE used for power generation already included inelectricity.2/ Does not include 475,000 TOE used for power generation alreadyincluded in electricity.3/ Historical growth rates in total energy consumption during theseventies are as follows:

1970-75 9.3% (BCL startedoperation in 1973)

1975-80 3.6%1970-80 6.4%

4.11 Three condensed energy balances appear in Annexes I (Tables I.7,I.9 and I.10) corresponding to the three scenarios outlined in para. 4.04and summarized below in Table 4.5.

- 48 -

Table 4.5

Energy Required in 1990 Under Three Possible Scenarios('000 TOE)

Case A Case B Case C(Gas)1/ (Coal) (BAU)

Production

Gas and Condensates 302 43 43Hydro 304 197 243

Plus Imports

Coal 304 447Petroleum 573 598 988

Less Exports

Condensates -178 -

Total Commercial EnergyRequired 1305 1285 1274

Less TransformationLosses (generationand other losses) -570 -550 -539

Total Final CommercialEnergy 735 735 735

Non-Commercial Energy 561 561 561

Total Final Energy 1296 1296 1296

1/ Annex I (Table I.8) also shows Case A (Gas) in detail with theproduction and export of methanol.

4.12 Energy inputs will be higher than the final energy consumptionshown in Table 4.4 by the transformation and transmission losses in theelectricity sector and by exports. The gross energy inputs are shown inTable 4.6 below.

- .49, -

Table 4.6

Forecast Gross Energy Inputs for 1985 and 1990('000 TOE)

1985 1990A B C

(Gas) (Coal) (BAU)

Final energy consumption 1073 1296 1296 1296Transformation losses 345 570 550 539Exports (condensates) - 178 - -

Total Gross EnergyInputs 1418 2044 1/ 1851 1835

1/ If exports of methanol are included in this case, transformationlosses would increase to 752,000 TOE, exports to 492,000 TOE, and totalinputs to 2,540,000 TOE.

4.13 The net imports ot fuels and their cost shown in Table 4.7below:

Table 4.7

Forecast Net Fuel Imports 1985 and 1990

1980 1985 1990A B C(Gas) (Coal) (BAU)

Imports of fuels in TOE (Table 4.5) 619 812 877 1045 988Cost of fuel imports (million

1980 US$) 188 287 290 319 381Less energy exports (million US$) - - 71 2/ - -

Net Energy import cost (million US$) 188 287 219 319 381

2/ Does not include exports of methanol which could be in the vicinityof 660,000 tonnes valued at US$ 137 million.

- 50 -

4.14 Although larger quantities are imported in Case B than in CaseC, the import bill is lower because cheaper coal substitutes for moreexpensive fuel oil used in Case C. Case A has an additional attraction(not included in Table 4.6) in that it provides gas at Port Moresby foran export-oriented petrochemical industry such as methanol. Roughcalculations suggest that a 2000 tons per day plant may cost aroundUS$300 million and increase energy exports by US$137 million per annumand make a gas pipeline to Port Moresby a more viable option.

4.15 If total exports of goods and services grow at 4% per annum from

1985-1990,1/ they will yield $1750 million in 1990 (1980 prices).Imports of energy in 1990 range from $219-$381 million, or from 13%-22%of export revenue (Table 4.7). Thus, if PNG does not exploit anyexportable energy resources, imports of oil will continue to cost theircurrently high share of export revenue (24% in 1980) eroding theincreased revenues from mining. In Case A (Gas) with exports ofcondensates and methanol, the deficit on energy trade falls to $82million (assuming methanol exports equivalent to US$137 million) or 5% ofprojected export earnings which is below its share in 1969-70.

4.16 These scenarios have been done only for the purpose ofillustrating the options available in the energy sector and the order ofmagnitude of energy imports and their costs. Detailed studies will berequired to estimate the profitability or otherwise of the differentcomponents of these three scenarios, or other scenarios.

I/ GNP is assumed to grow at the rate of 4% per annum during theeighties, perhaps higher in the first half as Ok Tedi starts production.

- 51 -

CHAPTER V

INSTITUTIONS AND POLICY PLANNING

Introduction

5.01 The Department of Minerals and Energy (DME) is the organizationwhich oversees most activities in the energy sector. The GeologicalSurvey Division within DME is responsible for technical advice on allexploration matters concerning the oil and gas sector, the coal sectorand geothermal sector, in addition to similar activities in the miningsector. The other major divisions of DME are the Bureau of WaterResources which is responsible for the collection of all hydrologicaldata relating to streams and rivers and evaluation of potentialhydroelectric sites, the National Weather Service and the Division ofMines, which is responsible for the implementation of the Petroleum Act,issuing of licences, monitoring of safety and the organization of thePetroleum Advisory Board (PAB). These four divisions are under theoverall supervision of the Policy and Planning Division, which hasresponsibility for coordination of negotiations over oil and gasconcessions and formulation of policy with respect to explorationactivities. The power sector is run by the Electricity Commission(ELCOM) whose chairman reports to the Minister of DME. Theorganizational chart of the DME as of November 1981 is shown in Annex VI.

5.02 In addition, a forum for interaction and exchange of informationamong the various parts of government on developments in the energysector is provided by the National Energy Planning Council (NEPC). Thiswas designed to be an interdepartmental group, with no executive powers,headed by the Minister of DME and representatives of the following:Department of Primary Industry, Office of Forests, National PlanningOffice, Department of Finance, ELCOM, Department of Works and Supply,Office of Village Development and Office of Environment and-Conservation. The Energy Planning Unit (EPU), which also reports to thePolicy and Planning Division, acts as the Secretariat for NEPC.

The Geological Survey Division

5.03 At present, the Geological Survey Division within the Departmentof Minerals and Energy, headed by the Chief Government Geologist, is incharge of exploration for minerals and petroleum. With regard to thelatter, it is responsible for the collection and review of pastexploration data from oil companies and for advising the PetroleumAdvisory Board on technical matters. The actual monitoring of contractsfalls under the Division of Mines of the same Department. From a briefreview of the Division's staff, it becomes readily clear that PNG lacksexpertise in petroleum matters such as petroleum engineering. About sixexpatriates and six PNG nationals, all exploration geologists andgeophysicists, look after both minerals and petroleum. Because of theimportance of oil and gas for PNG, and considering the need for earlyutilization of already firmed-up gas reserves and the possibility of

- 52 -

finding oil, it is recommeded that the existing group in the GeologicalSurvey Division be strengthened by hiring highly specialized petroleumexperts 1/. At a later stage consideration may be given to theestablishment of a separate oil and gas agency. Such an agency, whenformed, would include specialists in all areas of petroleum explorationand production. The new agency would be responsible for all aspects ofthe oil and gas sector including negotiation of contracts with oilcompanies as well as monitoring of contracts, duties now shared by theGeological Survey and the Division of Mines.

5.04 The Geological Survey Division also handles geothermalexploration and has a volcanological observatory, based in Rabaul whichmaintains seismic and geomagnetic monitoring stations throughout PNG.Only limited work has been done by the Geological Survey Division toestablish the geothermal potential. The same also applies to the coalsector. Although there have been reports of occurrences of coal andlignite, especially in the Gulf Province, in the Central Highlands andNew Britain and New Ireland, the DME has not promoted adequateexploratory work to establish reserves. This again might be anindication of the many varied responsibilities of the Geological SurveyDivision and the need for strengthening it in the area of coalexploration.

The Energy Planning Unit

5.05 The Energy Planning Unit was established at the end of 1978within the Department of Minerals and Energy for the purpose offormulating energy planning and policies. Its staff has increased from 2at the end of 1980 to eleven professionals, mainly expatriates, with itsmain expertise in the renewable forms of energy. The Government issuedin 1979 a "White Paper" prepared by EPU setting out PNG's energy plansand policies. The "White Paper" put the main emphasis on the productionof energy from renewable sources, and proposed many projects, some ofthem without adequate technical or economic appraisal. EPU did notconfine itself to energy planning, but also became involved in promotingenergy projects based on renewables. Some of these projects,particularly those dealing with ethanol, seem to have been initiatedwithout adequate data, and a cost reappraisal of these projects hasalready led to some of them being abandoned. The availability of atremendous biomass resource makes it a natural target for development inan energy hungry country like PNG. However, inappropriate technologiesseem to have been chosen for some of the utilization of biomass with theresult that substitution of oil by biomass in industry, other thanagricultural processing, has not taken place to any significant extent.

5.06 In view of the importance of energy planning in PNG, with its

1/ This is now being contemplated as a component of the second phase ofthe petroleum exploration project being financed by the Bank.

- 53 -

varied energy resources, it is recommended that the role of EPU beredefined as follows:

(i) EPU should function as an overall energy study andplanning agency, whose function will be to prepareintegrated energy plans, and not focus mainly on renewableenergy planning. Such integrated plans would be based ondemand and supply forecasts prepared by the respectiveagencies for power, coal, oil and gas and woodfuel and theuser sectors and sub-sectors. This would require closecoordination with, among others, ELCOM, the GeologicalSurvey, and the Forestry Office of Department of PrimaryIndustries (DPI). The expertise of EPU's staff should bediversified so that it can handle its new responsibilitiesas well as effectively monitor energy policies, programsand conservation measures.

(ii) In order to emphasize the importance of overall energyplanning, the promotion and implementation of renewableenergy projects and conservation measures could beentrusted to a separate unit under the Division of Policyand Planning.

ELCOM

5.07 ELCOM is a statutory authority, responsible for all aspects ofGovernment's public electricity supply system 1/. It was establishedunder the Papua New Guinea Electricity Act of 1961 under the Australianadministration and continued in this form after independence in 1975,under the authority of the Minister of Public Utilities and a Governmentappointed Board of Commissioners. In 1978, it was placed under theMinister of Minerals and Energy. This transfer took place at about thesame time as the establishment of the National Energy Planning Council(NEPC), which had a mandate to review and develop forms of renewableenergy (other than hydro) on an integrated basis. ELCOM's fortunes andauthority have, in a sense, declined in the period 1978-1981, while thoseof EPU, which was established in 1978 and was designed to act asSecretariat to the NEPC, have been in the ascendency. As a consequence,EPU eventually took over de facto responsibility for ELCOM's majorplanning, generation, and transmission facilities in the context of itsnational responsibility.

5.08 In March 1981 the Electricity Commission (Amendment) Act, 1981amending the Electricity Commission Act, 1961 - was passed whereby (i)the composition of Commission Membership was changed: the six members toinclude the Secretaries of Finance, Minerals and Energy, and Lands andthe Director of the National Planning Office, and two persons appointedto represent the private sector, (ii) the General Manager would no longer

1/ With the exception of Government Class C (very small) stations.

- 54 -

be a member of the commission and (iii) the previous Commissioner -General Manager was relieved of his post. The head of the EPU wasconcurrently appointed interim General Manager of ELCOM, becoming head ofboth organizations. The period of appointment terminated early in 1982,when the incumbent left both EPU and ELCOM.

5.09 ELCOM has operated with three departments (commercial,management, engineering) and several divisions and sub-divisions(electrical, generation, transmission/distribution, finance,administration, supplies and more recently, provincialelectrification). Within this framework there have been considerableshifts in organizational and personnel emphasis, e.g. expatriates vsnationals in positions, numbers and depth of responsibility. Thus, thenumber of expatriates decreased substantially in 1974-6, remained steadyuntil 1979 and increased sharply in 1980. This latter trend reflected adecision by ELCOM to do more in-house 1/ (in particular, its own designand construction), and about 30 expatriates were hired for the purpose.

5.10 In-house design and construction was certainly inadvisable for autility of the moderate size but considerable complexity of ELCOM. Inthe Commissioner's Policy Paper of July 1981 to the National ExecutiveCountil, ELCOM reversed its stand and in future, design and constructionwill be done by consultants and the private sector. Among otherdeficiencies focused on by management consultants and the "new"management (EPU-ELCOM common chief) were: the approach to nationalizationof staff, training, planning, management reporting cum decision making,tariff structure, financial control of projects, salary levels andrecruitment.

5.11 Planning capacity at ELCOM, has not been adequate. The SystemsPlanning Division was not given authority to select and analyze a rangeof generation options, being told which option to analyze by Design andContracts. The most common criticism is that ELCOM, traditionallymanaged by expatriates till independence, deteriorated considerably wheninadequately trained nationals took over much of management. However,even with the shift back to expatriates and EPU's intervention in thelast 2-3 years, the decline in planning has continued, although someproblems faced have at least been checked. Furthermore, some of the moreintractable problems had their genesis in the pre-independence era; forexample, the Ramu hydro concept and design.

5.12 The new management appointed to run ELCOM from early 1982,comprises a general manager, who has been appointed for five years, and ateam of four specialists from Montreal Engineering. Senior nationals inresponsible positions are to work with the team over a three-year periodin order to obtain experience so that they can ultimately replace them.These nationals will also be given training in their fields in foreigncountries. The result of these changes will depend much on the qualityof the new general manager and the Montreal Engineering team. If between

1/ The Pauanda hydro plant was designed by ELCOM staff.

- 55 -

them they have extensive experience in moderate sized utilityadministration and the capability to do power systems planning asdistinct from design and engineering, success is likely, more so if theycan change the episodic manner in which planning has been and is beingdone.

Bureau of Water Resources

5.13 The Bureau of Water Resources (BWR) is responsible for the

collection of all hydrological data relating to streams and rivers, andevaluation of potential hydroelectric sites. The interaction between BWRand ELCOM in the past has been inadequate and could have resulted in sub-obtimal planning of hydroelectric generation. As the major energyresource of PNG is its vast hydroelectric potential, the misison hasrecommended:

(a) an inventory of all large (50 MW plus) hydro sites, sothat preliminary feasibility studies can be made for 3-4of these sites for potential development of metallurgicalenclaves;

(b) investment in about 75 gauging stations on small rivers(with a potential of 10-50 MW) throughout the country.

The mission recommends that this work be entrusted to BWR. In addition,the mission recommends that interaction between BWR and ELCOM bestrengthened in the selection and planning of all future hydropowerstations, with BWR identifying potential hydropower sites and ELCOMdetermining the potential capacity and the necessary investmentdecisions.

- 56 -

CHAPTER VI

ENERGY SECTOR INVESTMENT

6.01 Over the past seven years, public investment in the energysector has been confined to the power sector. Annex II shows ELCOM'sinvestment program over these years which seems to have declined in realterms over the past three years.

6.02 During the same period, there has been private investment in theenergy sector by BCL for the 3x45 MW sets being used for captivegeneration. There has also been some additional investment by industryand commerce for power generation in small diesel generating sets. Amuch larger volume of private investment, (except for the subsidy underthe Petroleum Subsidy Act during 1954-68) has gone into oil and gasexploration.

6.03 Possible investment outlays in the energy sector (excludingpetroleum exploration and coal prospecting) under the three scenariosoutlined in para.4.04 up to 1990 have been very roughly quantified by themission and are shown below in Table 6.1. Petroleum explorationactivities have recently picked up and current exploration expendituresmay reach a figure of US$30-40 million per annum, all of it by theprivate sector. It is rather difficult to predict future investment inthe oil and gas sector as it would depend on the number and size of newdiscoveries and these investments are therefore not included in 6.1. Avery preliminary cost estimate of US$240 million for Pasca fielddevelopment with recovery of condensates and gas pipeline to Port Moresbyis, however, included.

6.04 Besides the development of the gas fields, the other majorinvestment would be in the electricity sector, by ELCOM, BCL and OkTedi. Investment cost per unit of capacity installed, especially forhydro, varies widely with the type of plant, scale and location. Variousfigures have been derived from different sources and are used for theinvestment figures in Table 6.1. Ok Tedi energy investments (including6x3.6MW diesel sets and the 46MW hydro plant at Ok Menga) are roughlyestimated to cost US$168 million. BCL investment in the energy sectordepends on the option from available choices--use of imported oil orimported coal or hydro or a combination of these. The most economic interms of capital costs (in contrast to operating costs) would be tocontinue with oil, and the most expensive would be to switch to coal forthermal generation and development of new hydro with a storage dam.Investment figures for BCL therefore vary from US$50 million to US$280million. ELCOM investments are estimated at US$157 million to US$210million over the next 8 years. Table 6.1 gives an idea of investmentforecasts for the energy sector up to 1990. These figures are largelyillustrative, given the considerable differences between the variousscenarios and the lack of reliable cost estimates.

- 57 -

Table 6.1

Investment in the Energy Sector 1981-1990 1/(Million US Dollars)

Case A Case B Case C(Gas) (Coal) (BAU)

ELCOM

Investment to 1985 2/ 140.0 140.0 140.0Other investment 15.0 15.0 15.0Port Moresby electricity 12.0 43.5 67.5

Gas Field development 150.0 - -

Gas Pipelines to 'Port Moresby 90.0 - -

BCL - hydro 150.0 - -BCL - coal 132.0 200.0 49.4

Ok Tedi diesel 18.0 18.0 18.0Ok Tedi hydro 150.0 150.0 150.0

Total 4/ 857.0 3/ 565.0 440.0

1/ The estimates for hydro investments are based on figures from CT Mainfor a variety of hydro projects, most of which have capital costs (in US$1980) in the range $1500-2500/kw capacity for run-of-river. Diesel costsare assumed to be $800/kw, coal between $1350-1500/kw depending on scale,and oil fired thermal $1000-1125/kw. The coal and oil figures are takenfrom consultants' reports for BCL.2/ Includes investment in Barikewa gas turbine ($34.0 m) and Rouna 4($37.0 m), Pauanda ($19.6 m), and Warangoi ($49.4 m).3/ Does not include investment in a methanol plant estimated at $300million.4/ Does not include investment in coal prospecting, which may amount toabout US$3 million over the decade.

6.05 Table 6.1 sheds light on possible energy sector investmentdepending on the supply side scenarios discussed in Chapter IV. With theexclusion of exploration expenditure of oil and gas ($30-$40m per annum)and investment in a gas based export oriented petrochemical plant at PortMoresby under Case A (about $270 - $300 m), investment can vary fromUS$430 million for Case C, US$555 million for Case B and US$847 millionfor Case A. Although Case A (Gas) appears high, Table 4.7 showed that itcould reduce the import bill by $162 million per annum compared with

- 58 -

Case C(BAU). These comparisons ignore other costs, but help place theinvestment levels in perspective. The cost/benefit ratios of thesevarious options and the recurring savings in fuel import costs have,however, to be carefully evaluated before investment decisions are made.

ANNEX I

Page 1 of 13

Energy Balances

Details of Forecasting Methodology

1970, 1975, 1979 and 1980 Balances (Tables I.1 - I.5)

1. The first step was to construct energy balance for "1970","1975" (actually averages of fiscal years 1969/70 and 1970/71, 1974/75and 1975/76) 1979 and 1980 (since there was evidence to believe that 1980was a somewhat atypical year). These balances were based largely onimport data for liquid fuels, data from ELCOM for electricity productionand use, and EPU data in woodfuel consumption. Industrial fuel use wasbased on Newcombe's survey of fuel use in Lae and evidence collected byEPU, and discussed in paragraphs 2.11 - 2.20 of the text. The energybalance for 1980 is also shown in original units in Table 1.4 (to showthe link to the historical data).

Energy Balance 1985 (Table 1.6)

2. Forecasts for fuel consumption for 1985 and 1990 were then basedon estimates of sectoral growth rates, fuel substitution possibilities,and likely developments in each sector as set out in Chapter 4. Forexample, BCL's projection of power demand, and Ok Tedi's development planwere used to project fuel demands by the mining enclave, while thegradual substitution of biomass for oil in the agricultural processingindustries, described in para. 2.16, allowed oil demands in non-miningindustry to be projected.

3. The 1985 forecasts could be checked against two other forecastsmade in the recent past: that by the Oil Supply Option Study and Mobil(Private Communication). The results are given below:

Forecast Oil Imports for 1985('000' metric tonnes)

Central Forecast Range OSOS MobilLPG 5 4 - 6 4.5Avgas 7 5 - 9 9 6.5Mogas 98 90 - 110 103 91.4Avtur 50 47 - 68 66 57.0Kerosene 22 17 - 26 26 17.0Distillate: Agriculture 5

Transport 133Mining 49Other Indus. 28Electricity 126Total 341 231 - 415 344 328

Fuel Oil 285 137 - 305 280 249Coal 0 0 - 218Total 808 653 - 964 73W

- 60 - ANNEX IPage 2 of 13

Energy Balance 1990 (Tables I.7 - I.10)

4. The 1990 forecasts could not be checked against other forecasts,and are in any case more speculative. Three separate supply scenarioshave been constructed to illustrate the range of possible options open tothe economy.

5. Finally, the underlying development of the economy can be better

appreciated by excluding the enclave mining and gas-based exportsector. Table I. 11 below is directly comparable to Table 2.2 of thetext.

ANNEX IPage 3 of 13

TABLE I. 1

ENERGY BALANCE - PAPUA NEW GUINEA - 1970(in thousands of metric tonnes of oil equivalent a/)

IEA Col No. 3 4a 4b 4c 4d 4e 4f Total 7 8 9IEA Motor Petroleum Total Non- TotalRow Gaso- Kero- Distil- Residual Products Elec- c/ Cols Commer- ColsNo, ____ _ LPG Avgas line Avtur sene late Fuel Oil. Incl _.PG _ Hdro tricity- cial 9-10

IIndig.Prod 41 41 343 3842 Imports 2 17 58 31 9 99. 12 228 228 228

6 Total Egy Req. 2 17 58 31 9 99 12 228 41 269 343 612

Transformat Jor_ns

9 Elec.Generation -18 -18 -41 16 -43 -43

13 Energy SectorUse & Loss

-1 -1 -la,

Total Final.14 ConstumptioLn 2 17 58 31 9 81 12 210 15 225 343 S68

Miiiing18 Otlher 1 13 12 26 10, 36 26 6219 Transport

20 Road 58 54 112 112 112:'2 Air 17 31 48 48 4823 Coastal 11 ll 11 1124 ot:her Sectors

25 Agc. 3 3 3 325 Commerce 1 1 1 2 227 I;ub.Service 1 1 128 Domestic

Rulral 4 4 4 307 311Urbari s 5 3 8 10 18

Note /a Onecietric ton of oil equivalent is defined as 10 million K calllb Calculated equivalent power plant input assuming 28% efficiency./c Calculated at 860 Kcal/kWh.

ANNEX I

Page 4 of 13

TABLE I. 2

ENERGY BALANCE - PAPUA NEW GUINEA - 1975(in thousands of metric tonnes of. oil equivalent a/)

IEA Col No. e 4a 4b 4c 4d be 4f Total 7 8 9IEA liotor Petroleum . Total Non- TotalRow Gaso- Kero- Distil- Residual Prodtucts Elec-/ Cols Commer- CobNo0. IPG _Avgas l ne Avtur sene __ ge Fuel Oil . LP !ydZ. tricitv 3-8 _al 9-10

1. Indig.Prod 64 64 389 4532 Imports 3 13 87 30 14 168 188 503 503 503

6 T'otal Egy Req. 3 13 87 30 14 168 188 503 64 567 389 956

Iranisformations

9 Llec.Generattion -31 -181 -212 -64 87 -189 -189

13 Energy Sector IUse & Loss -3 -3 -3-

'rotal Final14 Consumption 3 13 87 30 14 137 7 291 0 84 375 389 _ 76415 Industry

Mininlg 21 21 58 79 7918 Othier 2 27 7 36 ],3 49 38 87

19 Transport

20 Road 87 72 159 159 15922 Air 13 30 43 43 4323 Coastal 14 14 14 1424 Other Sectors

25 Agr. 3 3 3326 Commnerce 1 1 2 4 6 627 Pub.Service 3 3 328 Domestic

Ruiral. 5 5 5 335 I340Urban _ 8 6 14 16 30

Note /a Onemetric ton of oil equivalent is defined as 10 million K cal/b Calculated equivalent power plant input assuming 28% efficiency

/c Calculated at 860 Kcal/kWh.

ANNEX IPage 5 of 13

TABLE I. 3

ENERGY BALANCE - PAPUA NEW GUINEA - 1979(in thousands of metric tonnes of oil equivalent a/)

IEA Col No. 3 4a 4b 4c 4d 4e 4f Total 7 8 9 10LEA Motor Petroleum Total Non- TotalRow Caso- Kero- Distil- Residual Products Elec- C/ Cols Commer- C019No. _ LPG Avgas line Avtur sene late Fuel Ol Incl. LPC Hydro&b tricity _ cial_ 9-10

I Indig.Prod 107 107 420 5272 Imports 4 0 92 49 19 206 213 592 592 592

6 Total Lgy Req. 4 9 92 49 19 206 2]3 592 699 420 1119

Tranlsformat ionls

9 E].cc. -18 -202 -220 -107 104 -223 -223Generationl

13 Energy SectorUse & Loss -5 -5 -5

14 Cousumption 4 9 92 49 19 188 11 37299 471 420 891

15 industryl

I-ining 35 35 65 100 100l8 O the r 2 33 11 46 15' 61 42 103

19 TransLport

20 Roadi 92 98 190 190 19022 Air 9 49 58 58 5823 Coastal 19 19 19 . 1924 Other Sectors

25 Agr. 3 3 6 3 326 Commerce 1 1 427 Pub.Service

728 Domestic 1 5 51'ural 8 8 8 356 364Urban 1 10 10 * .9 20 22 3 42

Note /a Onemetric ton of oil equivalent is defined as 10 million K cal7b Calculated equivalent power plant input assuming 28% efficiency/c Calculated at 860 Kcal/kWh.

ANNEX IPage 6 of 13

TABLE I. 4

ENERGY BALANCE - PAPL'A NEW GUINEA - 1980

(original. units)

LA COL. NO. Total.IFA COL. NO. 3 4a 4b 4c 4d 4e 4f Petroleum 7 8 91

POW Motor Residual Products Total Non- Total Co:NO. __ _ LPG Avgas Gasoline Avtur Kerosene Distillate Futel Oil CL L - ydro /i -eticiryC Cola.3-9 Coa-eci a oa Col-TOE k. , E- - _.. Kwhr. M_ Kwhr. O OINLS OIL .UIVALLT

1 Indig.Prod 316 90 434 5242 liiport6 4 11 1f7 60 23 276 2:33 619 619 619

6 iotzol Egy Req. 4 11 117 60 23 276 233 619 316 709 434 1143

Trans farinalionls

9 EI ec. -45 -226 -248 -316 1253 -232 -232(;eLueration

1-3 Energy Sector . 57 --4 -4 1IJste & Loss sN

Total Final 4 11 117 60 23 231 7 371 1196 473 434 90714 Consullp t i on

15 Thdustr.

lNltriuiig 41 35 774 101 10118 ()ther 2 38 7 40 164 54 48 102

19 Transport

20 Road 117 124 195 195 19522 Air 11 60 57 57 5723 Coastal 24 20 20 2024 Other Sectors

25 Agr. 4 3 3 326 Coolmmerce 2 2 82 9 92 7 Iiib. Service 1 1 59 6 628 DIomestic

Rural 10 8 8 363 371Ilrb}anl 1 12 10 117 20 23 45

Note a/OneLetric ton of oil equivalent is defined as 10 million K cal

b/Calculated equivalent power plant input assuming 28% efficiency or 3070 Kcal/kWh.c/Calculated at 860 Kcal/kWh.

ANNEX I

TABLE I. 5 Page 7 of 13

ENERGY BALANCE - PAPUA NEW GUINEA - 1980(in thousands of metric tonnes of oil equivalent a/)

IEA Col No. 3 4a 4b 4c 4d 4e 4f Total 7 8 9 10IEA M4otor Petroleum Elec- Total Non- TotalRow Gaso- Kero- Distil- Residual Products Hydro triCi- Cols Commer- ColsNo. LPG Avgas line Avtur sene late Fuel Oil Incl. LPG /b t c 3-8 cial 9-10 _

I Indig. Prod 90 90 434 5242 Imports 4 8 90 49 19 233 216 619 619 619

6 Total Egy Req. 4 8 90 49 19 233 216 619 90 709 434 1143

Transformations

9 Elec.Generation -38 -210 -248 -90 106 -232 -232

13 Energy SectorUse & Loss -4 -4 -4

14 Total Final Consumption 4 8 90 49 19 195 6 371 102 473 434 907

15 IndustryMining 35 35 66 101 101

18 Other 2 32 6 40 14 54 48 102

19 Transport 288

20 Road 90 105 195 195 19522 Air 8 49 57 57 5723 Coastal 20 20 20 2024 Other Sectors

25 Agr. ~~~~~~~~~~3 3 ,3 326 Commerce 2 2 7 9 927 Pub. Service 1 1 5 6 628 Domestic

Rural 8 8 8 363 371Urban 1 10 10 10 20 23 45

-~~ ~ ~~~ I . _ I I .Note /a One metric ton of oil equivalent is defined as 10 million K cal

/b Calculated equivalent power plant input assuming 28% efficiency or 3070 Kcal/kWt,{c Calculated at 860 Kca1jkh,

ANNEX IPage 8 of 13

TABLE I. 6

ENERGY BALANCE - PAPUA NEW GUINEA 1985(in thousands of metric tonnes of oil equivalent a/)

IEA Col No. 3 4a 4b 4c 4d 4e 4f Total 7 n 9 10IeA Motor Petroleum Elec- Total Non- TotalRow Gaso- Kero- Distil- Residual Products trict- Cole Conner- CoUsNo. LPG Aveas line Avtur sene late Fuel Oil Incl. LPG Hvdro/b tVrc 7c clal 9-l2

1 Indlg.Prod ~ ~ ~ ~ ~~ ~d106 500 6062 Imports 5 7 103L 52 23 347 275 812 852 812

6 Total Egy Req. 5 7 103 52 23 347 275 812 106 918 500 1418

Transformations

9 Elec.Generation -128 -264 -392 -106 160 -338 -338

13 Energy SectorUse &'Loss -7 -7 -7

Total Final ON14 Conisumption 5 7 103 52 23 219 11 420 153 573 500 1073 1

15 Industry _ - . _____

Mining 50 5 55 104 159 15918 Other 2 1 29 6 38 22 60 70 130

19 Transport 0

20 Road 103 114 217 217 21722 Air 7 52 59 59 5923 Coastal 21 21 21 2124 Other Sectors

25 Agr.526 Conunerce 2 2 9 5 527 Pub.Service 1 1 6 ll28 Domestic

Rural 999 399 408Urban 1 12 13 12 25 31 56

Note- /a Oneriietric ton of oil equivalent is defined as 10 million K cal__ Calculated equivalent power plant input assuming 28% efficiency or 3070 Kcal/kWh./c Calculated at 860 Kcal/kWh./d of which possibly 2000 toe may be replaced by ethanol.

ANNEX IPage 9 of 13

TABLE I.7

Forecast 1990ENERGY BALANCE - PAPUA NEW GUINEA* - 1990

(in thousands of metric tonnes of oil equivalent a/) (Offshore gas without methanol)

llotncr f etroleu1 EleCc- Nln |(Caso- lnero- OistIl- sI- sld,.al . Products Total Hydrc& trTott) Total Com-t, &- To

Coal Ca*6 NGL Aveas Avttr flr.nl' Fki o11 _MI __ - il

~~CQ~~~~ctiQn ~~~~~~112 1901I'aolftlWtf 304 112 1902 302 304 606 561 1167r ;,; a s 304. 7 .120 66 29 339 12 573 877 877 31 77 -

-18 !-.178 1 --178f.t~n 1:vSy R.q. _ 304 112 12 7 120 66 29 339 12 join m5

i l< .... f ,,eratf-)n ........ 8 -304 -997 -72 -7 2 -475 -304 218 -561 -561

- ~~~ ~~~~ ~~-9 -9 -9Tjt.t i i.:a] Consa. 0 13 12 7 120 66 29 267 12 501 526 0 209 735 561 1f2.jTt i: I .l cons. _f

12.,;1r. 13 8 1 173 7 80 80 138 218 21813 8 1 9529 42 34 76 88 .164

is., -.~ 120 146 266 266 266 266Ai, ~ ~ ~~~~~~~~~7 66 73 73 73 '73v 2.' I 22 28 28 28

Ai-. S: 5.rAgl. 5 ! 5 5 5 6C.;1 C S,erce .3 3 3 13 1 6 16

2u,tiUc S.erv1ce 1 1 1 7 S a

12 12 12 12 435 447IIr~~~~~~~~~~~~~~.sn 1 ~~~~~~~~~~~~~~~~~~~15 16 i . 17 33 33 71

L" t "i, isctctc to" of oil eulivJlorkt Is defils,d ae 10 mllliot K cai.7b C Ics,l-tsd eq.IvalenL pow.ir plant Iniput )a,uIIg %Z efflcj1uncy C/ Calculated at 860 Kcal/kWh.* This Energy Balance corresponds to Case A (Gas) except for the fact that

production and exports of niathanol are not included.

ANNEX ITABLE 1. 8 C Page 10 of 13

CONDENSED ENERGY BALAMCE Forecast 1990(in thousands of metric tonnes oil equivalent) Gas Case: (Offshore gas with )

.__ ___ ___ _ _ Methanol )Primary Gas PetroleumSolid Fuels & Products & .Total Non-Com-(Coal) NGL Liquids Total Hydro Electricity Commercial mercial Total

Production 798 798 304 1102 561 1663Irnports 304 - 573 877 877 877

Exports -178 -314 -492 -492 -492Total Energy Req. 304 620 259 1183 304 1487 561. 20L8

Transformations

Elec. gener. -304 -99 -72 -475 -304 218 -561 -561

Other trans. -508 326 -182 -182 -1S2

En. sector use .9 _9 -9

& loss0\

Total Final Cons. 0 13 513 526 0 209 735 561 1296

Ind us try

l'nin g 80 80 138 218 . 218

Other 13 29 42 34 76 88 164

Transport 367 367 0 367 367

Other 37 . *37 37 74 473 547

TABLE 1. 9 ANNEX IPage 11 of 13

CONDENSED ENERGY BALANCE Forecast 1990(In thousands of metric tonnes oil equivalent) Coal case

Primary Gas PetroleumSolid Fuels & Products & Total Non-Com-(Coal) NOL Liquids Total Nydro Electricity Commercial mercial Total

Production 43 43 197 240- 561 801

Imports 447 598 1045 1045 1045Exports

Total Energy Req. 447 43 598 1088 1285 561. 1846

Transformations

Elea. gener. -447 -43 -72 -562 -197 218 -541 -541Other trans.

En. sector use

6 loss -9 -9 .9Total Final Cons. 0 526 526 209 735 561 1296

Industry

tilning 80 80 138 218 218Other 42 42 34 76 88a 164

Transport 367 367 0 367 367

Other 37 37 37 74 473 547

ANNEX ITABLE I. 10 Page 12 of 13

CONDENSED ENERGY BALMNCE Forecast 1990(in thousands of metric tonnes oil equivalent) (Business as usual)

Primary Gas PetroleumSolid Fuels & Products & Total Non-Con-(Coal) NGL Liquids Total Hydro Electricity Commercial mercial Total

Production 43 43 243 286 561 847

Imports 0 988 988 988 988

Exports .

Total Energy Req. 0 43 988 1031 1274 561. 1835

Transformations

Elec. gener. -43 -462 -505 -243 218 -530 -530

Other trans.

En. sector use

& loss -9 _9 -9

Total Final Cons. 0 0 526 526 209 135 561 1296

Industry

Mining so 80 138 218 218

Other 42 42 34 76 . 88 164

Transport 367 367 0 367 367

Other 37 37 37 74 473 547

- 71 - ANNEX IPage 13 of 13

TABLE I. 11

PROJECTED ENERGY CONSUMPTION EXCLUDING COPPER AND EXPORTS

Rate of Growth1980 1985 1990 1980-85 1985-90'000 tonnes oil equivalent % p.a.

Total energy required 876 1,053 1,294 3.7 4.2

Total commercial energyrequired 464 555 733 3.6 5.7

Total final commercialenergy consumption 373 414 517 2.1 4.5

.Total commercial energy required by sector, amounts and percentages ( )

Transport 275 (59) 297 (54) 367 (50) 1.6 4.3

Industry 87 (19) 124 (22) 179 (24) 7.3 7.6

Domestic 54 (12) 69 (12) 97 (13) 5.0 7.0

Other 48 (10) 66 (12) 90 (12) 6.6 6.4

- 72 -

ANNEX IIPage 1 of 5

THE ELECTRIC POWER SECTOR IN PNG

1. In PNG the power sector comprises: The Papua New GuineaElectricity Commission (ELCOM), responsible for the public power supply;Bougainville Copper Ltd., (BCL), which generates a substantial amount ofthe power produced in the country for captive consumption, and privateconsumers who have provided their own generating plant in the form ofsmall diesel generating sets.

2. The scattered islands and the extremely rugged and in someplaces inaccessible mountain ranges on the mainland eliminate anypossiblity of a fully integrated power system. As a consequence, ELCOMoperates three power networks which account for about 75% of its load:Port Moresby and environs; the Ramu system extending from Lae on the eastcoast to the Highlands, and Rabaul. It also operates small isolatednetworks supplied by diesel and in a few instances, small hydro stations,classed as 'B' stations, in that they are deemed financially self-sustaining. In addition, it operates on behalf and at the expense ofGovernment 'C' class stations, of small size, and scattered over morethan 100 locations. Map 16281 identifies ELCOM's operating centers,while Table II.1 gives the total installed capacity and generation in PNGat the end of 1980. BCL with 41% of capacity has contributed to 61%o oftotal generation (and consumption), while ELCOM with 51% of capacity hascontributed to only 32% of generation. The class "C" centers represent2.5% of total generation or about 6% of ELCOM capacity.

TABLE 1I.1

Total Installed Capacity and Generation in PNG as of Dec. 1980

-------Installed Capacity ------- GenerationHydro Thermal Total (GWh) %

ELCOM 94 73.7 167.1 (51.3) 414 (32.1)

Government - 10 10 (3.0) 31 ( 2.5)

Bougainville Copper - 135 135 (41.1) 790 (i.3)

PNG ForestProducts 5.5 - 5.5 (1.6) 23 (1.8)

Other Private - 310 10 (3.0) 30 ___.3)

Q9.5 228.7 329.6 (100) 1288 (100.0)

'1 Includes diesel generating sets.

2/ Based on an estimated annual load factor of 35%.

-73 - ANNEX IIPage 2 of 5

3. As already mentioned (para.2) ELCOM operates three powernetworks which account for about 75% of ELCOM's load: the Ramu system,Port Moresby and environs, and Rabaul. For the Ramu system, theinstalled capacity is 65MW, but the reliable rating is only 25MW, orabout 45%. At the run-of-river Ramu hydro station with 45MWinstallation, dry season reliability output is 11MW. Currently, one ofthe three units is shut down for turbine rebuilding for a year, a processlikely to be repeated for the remaining two. Diesel capacity is limitedby unit availability since some units are often shut down for repairs.The system comprises a transmission network operating at 66KV (built for132 KV) connecting Lae (the main industrial center of PNG), Goroka, MountHagen and Madang with the Ramu hydro station. Outage of a portion ofthis transmission system has serious impact and necessitates substantialload shedding.

4. The Port Moresby system supplies the city itself and ruralenvirons. Power is transmitted from the Rouna plants at 66KV.originally designed for regulated inflow by the upstream Sirinumureservoir on the Laloki River, the hydroplants were seemingly intended toprovide power on the following basis:

Name Annual FirmPlate Capacity Energy Production Plant Factor

Average year 49 MW 150 Gwh 35%Dry year 49 MW 97 Gwh 23%

However, with the near depletion of the Sirinumu reservoir in 1980, dueto the preceeding unusually dry period and mismanagement of the reservoirdischarge, the Rouna hydro facilities have been operating for the pastyear at very limited load, in part to replenish the reservoir. Base loadis being provided instead by the 20MW gas turbine installed at Moitakalate in 1979. Cost of expenditures on distillate fuel for the gasturbine was K 7 millin in 1980.

5. The Rabaul system on East New Britain Island with a demand ofabout 5.5 MW, is supplied by diesel aggregating 17 MW, which is in verypoor condition. ELCOM decided recently to rehabilitate the dieselfacilities at substantial cost to enable the system to continue to besupplied until the new hydro station, Warangoi (10MW), now underconstruction, begins operation in 1983.

74 ~~~~ANNEX II

Page 3 of 5

6. Capital investment by ELCOM during the period 1973/74 and 1980is given in Table II.2 below.

TABLE II.2

ELCOM Investment 1973/74 - 1980

O(illion Kina)

Construction Expenditure InvestmentCurrent Prices (1980 Prices)

1973/74 14.16 24.5

1974/75 17.86 26.7

1975/76 15.19 20.8

1976/77 20.72 26.5

June-Dec. 1977 6.96 8.8

1978 12.96 15.4

1979 13.05 14.6

1980 7.65 7.6

Total 108.6 144.9

-75 - ANNEX IIPage 4 of 5

Operating Statistics

7. Generation and sales statistics and other pertinent informationfor ELCOM during the period 1974-80 are shown in Table II.3 below:

TABLE 11.3

ELCOM'S OPERATING STATISTICS

1974/75 1975/76 1976/77 1977_1/ 1978 1979 1980(half year)

Installed capacity (MW) 88.2 104.3 126.5 127.7 127.9 159.5 169.13Maximum demand (MW) 44.0 48.2 51.5 61.0 64.4 79.9 79.05Energy generation (Gwh) 279.6 309.0 334.1 175.0 369.8 440.1 465.0Energy sales (Gwh) 255.8 274.0 302.9 153.33 338.8 379.6 409.3System losses (%) 8.5 11.3 9.3 12.4 14.6 13.8 12.5Load factor 2/ (Z) 66 65 67 - 70 56 59

No. of consumers- Domestic 21,805 23,435 24,911 25,440 26,721 31,377 32,179- General Supply 4,848 4,954 5,158 5,393 5,611 6,797 7,223_Maxmu- demand 21 20 21 22 24 29 30-Public lighting 1 1 1 1 1 1 1

Total 26,675 28,410 30,091 30,856 32,357 38,204 39,433

No. of employees- Expatriate 207 166 123 135 134 127 179- National 1.553 1.667 1,790 1,795 2.156 2,420 2,566

Total 1,760 1,833 1,913 1,930 2,290 2,547 2,745

No. of consumers peremployee 15 15 15 16 14 15 14

Sales per employee -

(kWh) 143,340 149,482 158,338 - 147,948 149,038 149,107

1/ Since 1977, ELCCM's fiscal year is January-l - December 31.

2/ Load factor is non-coincedental.

3/ ELCCM's generation centers are isolated and because of this the number ofconsumers per employee is low.

The system maximum demand (non-coincedential) was about 80 MW in 1980 as in 1979reflecting the effect of suppressed demand and conversion fromelectricity tocsolar water heating. These two factors probably are responsiblefor the maller load factor, 592 compared with the earlier 66Z.

- 76 - ANNEX IIPage 5 of 5

8. The load growth for ELCOM in the 1976-80 period averaged 9.3%p.a. with household consumption at 8.2%, commercial/light industries at8.9% and heavy industries at 14.8%. Out of the total sales, householdsales constitute 29%, commercial/light industries 59% and heavyindustries 12%. Although the number of domestic consumers increased byover 30% during this period, the total number of domestic consumers in1980 was only about 32,000 representating about 5% of the totalhouseholds but nearly 50% of the urban households. Table II.4 conveyssome idea of the relative access to electricity supply in the PortMoresby area and that served by the Ramu network, constituting 63% of allELCOM domestic consumers but containing only a small fraction of thecountry's population, some 240,000 people.

The average annual domestic consumer usage was practically constantthrough the period at about 3,600 kWh, or 300 kWh per month, which isfairly high for a developing country, and is an indication of the urbanenclaves characteristic of PNG.

9. In the Government's Energy Policy "White Paper" of 1978, somereservations were expressed concerning rural electrification (RE): thatwhile it had become something of a password for development in the ThirdWorld, it was unlikely to be valid in the context of rural Papua NewGuinea. The paper questioned the validity of the usual benefitsattributed to RE, be*ter standards of education and literacy, lowerpopulation growth, reduced migration and improved quality of life in thevillages, and thought they could each be achieved more readily by othermeans. The problems of providing RE in PNG cited, with somejustification, were the economic impracticability of providing ruraltransmission or diesel generation given the isolation and distance ofmost villages and the terrain, and the ability and willingness of thevillagers to pay for connection and usage.

TABLE II.4

Msttmatea Access to Electrec±tv I/in Major Areas (as of Mid-1960)

Number ofEstimated Domestic Estimated

Center Population Consumers Access

Port Moresby 122,761 12,479 51%

Lae 61,682 * 4,389 36%

.Madang 21,332 1,481 35%

Goroka 18,797 1,529 41X

Mt. Hagen 15,362 1,376 45%

1/ Based on an average of five people pe-- istallation.

- 77 -

ANNEX IIIPage 1 of 6

The Transport Sector

1. Virtually all gasoline is consumed by road transport, butdistillate is also used for marine transport, electricity generation, BCLown use (mostly graders, bulldozers, and concentrate drying) and otherindustrial use. Non-transport distillate fuel use can, however, beestimated, and subtracted from total imports to give an estimate for fueluse in road and marine transport. Table III.1 below gives figures forfuel use in transport (excluding air) for calendar years 1970-1980(before 1976 the calendar years are averages of adjacent fiscal years).

TABLE II1.1

Transport Fuel Consumption( 000 Kl)

Gasoline Distillate TotalRoad (Estimated

Road andMarine)

1970 76 75 1511971 91 111 2021972 97 116 2131973 98 175 2731974 102 91 1931975 113 100 2131976 113 98 2111977 114 121 2351978 118 136 2541979 120 138 2581980 117 154 271

From the table it is clear that 1970 appears somewhat atypical,as does 1973 for distillate. The latter figure may reflect inaccuraciesin assessing BCL fuel use in its early stage, as well as possible errorsin allocating fuel to different product categories in the importstatistics.

2. Since we wish to test the hypothesis that the transport fleet isbecoming more fuel efficient, the next step is to predict the fuelconsumption implied by the vehicle stock on the assumption of unchangingfuel consumption per vehicle. Table III.2 below gives vehicle stock databy category of vehicle.

-78 - ANNEX IIIPage 2 of 6

TABLE rII.2

Registered Motor Vehicles by Vehicle Type('000)

At 31 Dec. Car and Light Bus OtherStation Wagon Open Van Commercial

1970 17.3 7.4 0.3 4.81971 18.9 8.5 0.4 5.51972 20.1 8.3 0.4 5.91973 19.0 8.7 0.5 4.91974 17.3 9.4 0.7 6.31975 17.9 10.6 0.9 6.41976 17.7 11.1 1.1 7.01977 17.2 12.7 1.5 7.11978 17.2 13.5 2.0 7.11979 17.7 15.0 2.4 7.71980 est. 18.7 16.9 3.1 8.5

Source: PNG Statistical Bulletin 25, March 1981.

3. Table III.3 gives estimates of fuel consumption per vehicle,based on the 1979 Road Freight Transport Study. The percentage gasolineis based on Newcombe (1980).

TABLE III.3

Fuel Consumption Per Vehicle

Annual Distance Consumption Annual Cons. % GasolineOOOkm litres/lOOOkm Kl

Cars and station wagons 17.5 115 2.0 100Light commercial 40.0 190 7.0 78Bus 70.0 300 21.0 30Trucks (i.e. all others) 50.0 175 8.8 0

This table gives the following prediction equation for fuelconsumption based on unchanging fuel use per vehicle p.a.

Prediction Equation: ('000 KL)for gasoline = 2 x (cars and station wagons) + 5.9 (light open) + 6.3 (bus)for distillate = 2.2 (light open) + 8.8 (other commercial) + 14.7 (bus)

The final step consists in regressing the predicted fuel consumptionon the actual fuel consumption. The results of regressing predicted on actualgasoline consumption for 1970-1979 are

Predicted = - 18.2 + 1.18 actual r2 = 0.79

- 79 - ANNEX IIIPage 3 of 6

The fit is good and the slope is close to unity, as required. The slightdeparture from unity suggests a decrease in fuel consumption per annum pervehicle which is to be expected given the 72% real price rise of gasoline overthe period (see Table III.4). One might have expected such a considerableprice rise to have had a greater effect on fuel consumption, but it must beborne in mind that maintenance and depreciation costs are relatively muchhigher than fuel costs in PNG. Some evidence for this is provided by the highattrition rate of vehicles and their short life, shown in Table III.5. Onaverage, it appears that cars last only 5-6 years and hence depreciate attwice or more the rate they do in developed countries.

TABLE III.4

Gasoiine Diesel (Distillate)

fob price retail real price fob price retail real priceprice index price index

toea/litre Index 1970=toealitre Index 1973=103

1970 7.9 1001 8.4 107 *2 2.8* 8.7 104 2.33 2.7* 9.0 103 1.9 7.5 1034 12.6 111 11.4 1215 (7.2*) 7.9 16.2 133 6.3 12.7 1266 9.1 18.2 138 7.4 14.3 1307 9.0 20.5 149 8.0 15.6 1378 9.6 19.7 137 8.0 15.0 1269 12.1 22.3 145 10.9 18.3 14480 18.3 29.6 172 17.6 25.3 17781 19.3 36.8 194 18.8 32.9 209

Notes: fob price: * Fiscal year average1975 Jan, 1976 April, 1977 Tan., 1973 Feb, 1979 Jul-SeD,1980 av.

Retail price: Gazetted

Real price index: 1970 = 100, retail price deflated by CPIfor distillate, base is 1973 = 103. Figjresfor 1981 assumes 10% inflation 1980-81.

- 80 - Ax II

Page L o L

TABLE III. 5

.kttrition Rate of Vehicles

Numbers

Cars Coomercial Vehicles

Calendar New Increase "Deaths' % New Increase 'Deaths' %Year Reg. in Stock of stock lReq. in Stock of Stoc'-

1.976 1854 - 428 2282 17 5407 324 4083 231.977 1982 - 544 2526 20 6443 2057 4386 211.978 1928 - 266 2194 17 6003 1261 4742 22

Source: Summary of Statistics, 1978.

ANNEX IIIPage 5 of 6

4. The figures for estimated distillate consumption in Table III.1 arederived as a residual after deducting other identified uses. Since theoriginal figures for distillate are themselves subject to considerableuncertainty, they must be treated with caution. Omitting the figures for1973, which seems particularly suspect, the regression equation is

predicted = -11.2 + 0.9 estimated r2 = 0.60

The fit is not as good as with gasoline, but this is to be expected as thefigures for actual diesel consumption are not available. The average ratio ofpredicted to estimated is 88% (excluding 1973) and it could be argued that 88%of diesel is for road transport use. Newcombe's estimate is 80%, and if weaccept 84% as a compromise estimate, then the equation could be rewritten

predicted = - 7.2 + 1.07 (0.84 estimated) r2 = 0.60

again suggesting that the slope is above unity, as for gasoline. Again, thisis consistent with a fall in fuel consumption per vehicle p.a., reflectinggreater efficiency and a response to higher prices. This consumption responsehas been less strong than for gasoline, but trucking demand is presumably lessprice elastic than personal travel demand, and the effects of improved roadshave probably had a greater effect in lowering transport costs for heavyvehicles than for lighter cars.

5. Thus, transport fuel use has beep growing less rapidly than thevehicle stock, which shifts the problem of explaining transport fuel growthback to one of accounting for the growth in commercial vehicles in a stagnanteconomy. The GDP data show that the share of GDP at current factor costgenerated in the transport sector fell from about 6.0% at the start of thedecade to about 4.5% at the end, suggesting that the transport sector grew, ifanything, less quickly than the stagnant economy. It is hard to reconcilethis data with the growth in vehicle stock and fuel use. Moreover, taking thetonnage of exports of coffee, cocoa and tea as a measure of transport demandfrom the Highlands, the growth averaged 4.7% p.a. over the decade, somewhatbelow the growth in distillate consumption, but still higher than the growthin GNP.

6. Several explanations are possible. First, the transport component inGDP has been increasingly underestimated, and transport demand has beengrowing at a moderate rate. Second, personal mobility has probably beenincreasing (bus numbers have risen very rapidly), reflecting a change inconsumption habits towards more fuel intensive goods (transport services).Third, farmers may prefer to spend windfall gains on vehicles rather thanalternative consumption goods, and then find both productive and consumptionuses for them.

Implications

7. Transport fuel use constitutes the major oil demand, and, of thevarious oil users, is the one for which there are fewest alternative non-oilbased fuels. Future oil demand will depend critically on future transportdemand. Newcombe (1980) projected this by assuming that urban transport fuel

- 82 - ANNEX III

Page 6 of 6

use per capita would remain constant, but that urban population would rise at7.5% p.a. On this scenario the share of transport fuel in total fuel use(energy basis) is projected to rise from 35% to 60% by the year 2000, assuminga slow growth rate of 3% p.a. in per capita energy consumption.

8. This projection possesses little credibility, as it is difficult tobelieve that either urban migration will continue at past rapid growth ratesin a stagnant economy, or that new migrants will enjoy the same fuel use asthe current average, which is greatly increased by the presence of expatriatesand commercial/industrial demand.

9. It would seem more likely that transport demand will grow in linewith economic activity as a whole, possibly with an elasticity of aboveunity. At the moment transport use is very expensive because average vehiclelife is so low. Table III.5 shows that the vehicle death rate is more than20% for commercial vehicles, or, as a ratio to stocks of 3 years earlier,nearly 30%, suggesting an average life of less than 4 years. Clearly, theamortization costs are considerable. If maintenance and driving habitsimprove, operating costs will decrease, and presumably increase vehicle useand perhaps ownership rates.

- 83 -

ANNEX IVPage 1 of 1

PRELIMINARY ESTIMATE OF HYDROELECTRIC POWER POTENTIAL 1/

(Schemes of greater than 50 MW and costing less than $600 / KW)-

RIVER POWER DEVELOPMENT POWER OUTPUTBASIN ,B Nev.' Total

Kikori Lower Waga 45Upper Mubi 800Lower Mubi 2500

3700

Purari Kondiu-Asaro-Wahgi 1350Tua 2950Pio-Purari 1700

I Aure 130Lower Purari 1650

7800

Strickland Lagaip-Strickland 1500

Upper Ramu Upper Ramu 190

Musa Musa 400

Waria Waria 250

Mambare Mambare 100

Angabunga Angabunga 65

Yuat Yuat 150

Note 1/ Source: The Hydroelectric Potential of Papua New Guinea, AustralianDepartment of Housing and Construction, April 1974.

2/ Only the most promising schemes are listed here. Others may also beidentified in the course of preparing an inventory.

ANNEX VPage 1 of 1

COAL OCCURRENCES IN PNG

Rank Chemistry Dip Volume Transport Ease of Exploration MineMethod Transport Potential Potential

1980's

Finschhafen !Lignite ? ?Shallow Small Road to Finschhafen, Easy Small Nonesea to Pom

Kabwum Lignitic ? ?Shallow ?Small Road to Coast, sea Relatively Small Littleto Pom easy

Pindiu Sub-bituminous Moisture 19% ?Shallow 40-50 Construct road to Medium Good GoodAsh 9.4% million coast, sea to PomVM 40.2% tonnesFC 31.4% Specific Egy

23.9 MJ/kg

Madang Lignitic ? ? 30 Small Adjacent to coast Easy Small Little

co

Komewu ?Lignitic ? ? ? Shallow draught Medium ? ?vessel to Pom

Omati ? ? ? ? Construct road, Difficult Small Littleshallow draughtvessel

Hegigio Sub-bituminousLignitic ? ? Small Road construction in Extremely Small None(Cannel) extremely rough difficult

terrain, ? shallowdraught vessel to Pom

Hohoro ? ? 10 -30 ?Large Adjacent to coast, Easy Good Goodshallow draught

vessel

Lower Purari Sub-bituminous See Table 2 20 0-300 Large Shallow draughtRiver vessel Medium V. Good V. Good

-85 - ANNEX VIPage 1 of 1

Organizational Chart of DME as of Novemiber 1981

-{ ~~Minister- of DME

Secretary of ODME

Policy and Planning

Geological Bureau of F NationalSurvey Water Resources Weather Mines

Energy PlanningUnit (EPUI

ELCOMXiLands Finance, DME, NPO,

2 Private Sector)

World EBank-23726

- 86- ANNEX VIIPage 1 of 10

CONSUMPTION, PRICE AND IMPORT COST DATA

1. Data Sources

For Petroleum Products

1969/70 - 1975/76 Trade Statistics (Heavy distillateallocated to residual fuel oil)

1975 - 1980 Energy Planning Unit data, basedon trade statistics.

These data are presented in Table VII.1 below and are compared withthe data from the UN 1979 World Energy Statistics in Table VII.2.

For Electricity:

Production 1969/70 - 1978 are taken from UN 1979 World EnergyStatistics are shown in Table VII.3. These correspond closely to thosefigures available in the Summary of Statistics, 1978, which in turn appearsmore comprehensive than ELCOM figures, since they systematically includeGovernment production in "B" and "C" centres, and the private sector (BCL andPNG Forestry Products). The 1979 total comes from the Abstract of Statistics,June 1981, and the breakdown comes from Energy in Papua New Guinea 1981,EPU. BCL figures for 1979 - 1980 are estimated from oil consumptionfigures. 1980 figures come from ELCOM and EPU. Sales figures 1969/70 -1972/73 come from the annexes to the Bank's Second Power Project, presumablyfrom ELCOM, and later figures come from ELCOM. Different documents from ELCOMand EPU give different figures for some years, but it is hoped that thefigures below are consistent from year to year within categories.

For Woodfuel: (Table VII.4)

Population figures are the revised figures from Bank Report 3544a-PNG, dated Dec. 8, 1981, p.54.

Woodfuel consumption at 16 MJ per cap/day for rural households and 6MJ per cap/day urban households has been taken from Newcombe et al Energy forDevelopment: the energy policy papers of the Lae Project, 1980. p. 189.

These raw data for fuel consumption are then used to build up energybalances (Annex I) for '1970' (average of 1969/70 and 1970/71), '1975'(similarly an average of 1974/5 and 1975/6), 1979 and 1980, allocating fuelsto end use as explained in Annex I and the text.

TABLE VII.1 ANNEX VIIPage 2 of 20

PETROLEUM PRODUCT IMPORTS AND ALLOCATION TO ELECTRICITY

Thousand Kl

Year Avgas Motor Avtur Kerosene Distillate Residual fuel Petroleum used for Electricity

Oil generation 2/

_____ _____ ______ _________ ___________ ______________ Distillate 1/ Residual fuel Oil

1969/70 22 67 34 10 94 13 17 0

70/71 21 85 43 12 140 12 23 0

71/72 19 97 47 14 178 107 27 68

72/73 18 97 45 14 182 173 31 161

73/74 19 99 39 15 173 225 33 186

74/75 18 104 79 15 188 196 37 186

75/76 16 114 41 17 191 200 28 198

76/77 15 188 m

1975 3/ 17 113 37 17 199 201 195

1976 14 113 31 18 182 215 194

1977 12 114 35 19 200 231 203

1978 11 118 49 22 234 223 21 220

1979 12 120 61 23 244 228 21 217

1980 11 117 60 23 276 233 38 226

1/ Estimated from 0.3 litre/kWhr2/ 1969-72 estimated from 0.275 litre/kWh; 1975-80 actual fuel consumption.

3/ Note break in series, from fiscal to calendar years.

TABLE VII.2 ANNEX VIIPage 3 of 10

COMPARISON OF UN DATA WITH BANK DATA ON PETROLEUM PRODUCTS

('000 metre tonnes)

Year Avgas Motor Avtur Distillate Residual Total Liquids LPGGasoline Fuel Oil Oil Equivalent

UN Bank UN Bank UN Bank UN Bank UN Bank UN. Bank UN

1970 16 16 60 55 26 30 110 97 4 11 231 228 2

1971 10 15 66 .66 33 35 136 132 6 - 272 324 2

1972 16 14 84 71 44 36 168 149 83 120 414 420 4

1973 14 14 64 72 39 33 157 147 148 171 434 471 3

1974 15 14 78 75 31 30 193 150 125 181 506 485 2

1975 18 12 74 80 27 31 182 157 169 170 485 487 3

1976 13 10 93 84 32 25 188 153 125 208 515 485 3 X

1977 15 9 95 85 35 27 190 168 205 223 557 519 4

1978 18 8 100 87 40 39 190 197 220 215 585 556 4

1979 20 9 100 89 40 48 195 205 230 220 603 581 5

1980 8 91 47 232 224 608 4

Av. 70-79 460 456 3

TABLE VII.3 ANNEX VIIPage 4 of 10

ELECTRICITY PRODUCTION AND USE

Million KWhr

Total Electricity Public Electricity BCL BCL Losses DomesticThermal Hydro Total Diesel Hydro Total Thermal Use Consumption

Production

57 134 191 57 95 152 16 37

75 142 217 75 103 178 15 43

338 148 486 91 108 199 247 240* 18 48

690 158 848 103 119 222 587 568* 22 60

785 170 955 109 129 238 676 655 23 64

799 184 983 122 142 264 676 651 35 72 X

811 234 1045 92 208 300 719 692 34 74

734 281 1015 49 266 315 685 653 33 88

857 330 1187 60 310 370 797 754 54 96

868* 347* 1215 70 327 396 798 798 62 110

937* 316 1253 125 293 412 790 763 57 118

* Estimated

- 90 - ANNEX VIIPage 5 of 10

TABLE VII. 4

ESTIMATES OF DOMESTIC WOODFUEL CONSUMPTION

Year Total Urban Woodfuel ConsumptionPopulation Population

'000 '000 '000 toe UN Series'000 cu. m.

1970 2394 192 317 4250

1971 2450 208 - 324

1972 2505 225 330

1973 2563 243 336

1974 2622 262 343

1975 2684 282 350 4753

1976 2746 302 357

1977 2809 323 364

1978 2873 345 371

1979 2939 367 378 5250

1980 3007 395 386

2. The historical series on retail prices for energy products arepresented below in Tables VII.5 and VII.6.

TABLE VII.5 PAgE 6o1Page 6 of 10

PETROLEUM PRODUCT PRICES IN PAPUA NEW GUINEA

US$ tonne

1971/2 1972/3 1974/5 1975 1976 1977 1978 1979 1980 1981

LPG fob 51.3 55.5 129.9 130 131 140 394 423 680 789cif 251 255 272 437 499 850 914

Avgas fob 56.8 62.9 158.5 146 170 174 204 275 848 736cif 157 187 194 227 290 836 754

Mogas fob 43.5 47.1 133.2 146 155 153 183 231 371 378cif 157 179 169 204 250 391 402

Avtar fob 33.0 37.3 115.4 113 125 125 150 246 356 355cif 124 141 144 172 261 377 378

Kero. fob 37.1 39.6 107.3 124 131 125 140 205 353 372cif 136 146 144 161 223 375 396

Distil fob 32.3 30.3 98.4 104 112 121 135 184 317 328cif 115 129 141 157 202 338 352

Res. fob 15.6 13.1 61.1 77 70 79 78 104 159 212cif 83 77 85 84 113 187 227

Notes on Price Data

For 1971/72, 1972/73, 1974/75, the Trade Statistics gave f.o.b. figures for petroleum products. 1975-81data comes from EPU Energy in Papua New Guinea 1981, and appears consistent where it can be checked against theBank's estimates of c.i.f. products (landed at Bougainville). The only exception appears to be the figures forAvgas in 1980 and 81, where the posted prices were closer to $620. However, since Avgas has such a small overallshare this should make little difference to the estimated import bill.

-92- ANNEX VIIPage 7 of 10

TABLE VII-6

ELECTRICITY TARIFF, PORT MORESBY

Domestic General Max Energy Fuel Cost Index oft/kWh Demand Charge t/kWh Real Domestic

K/KW t/kWh Diesel GT Electrici.tyPrice.1971 = 100

1970 2.5 3.05 2.6 1.91

1971 2.6 3.2 5.5 1.50 100

1972 2.6 3.2 5.5 1.50 94

1973 2.6 3.2 5.5 1.50 2.2 90

1974 Nov. 3.9 3.9 8.5 1.44-0.64 3.5 105

1975 3.9 3.9 8.5 1.44-0.64 4.0 97

1976 5.5 5.5 10.5 1.8 - 0.8 4.6 126

1977 5.5 5.5 10.5 1.8 - 0.8 4.9 122

1978 5.5 5.5 10.5 1.8 - 0.8 4.6 118

1979 Nov. 8.5 8.2 ? ? 5.8 168

1980 8.5 8.2 ? ? 8.2 10.7 150

1981 June 10.8 10.8 discontinued 10.1 13.1 173*

1982 Jan. 11.5 11.5

* Assuming 10% inflation in 1981.

Notes: Figures for domestic consumers are at the lowest rate (above 190 kwhr/

month until 1980, then above 40kwhr/month). The maximum demand tariff

Kina/Kw per month maximum 30 minute demand was discontinued in June

1981. For customers on this tariff the marginal costs (energy charge)

decreases to the lower figure shown above 5GWhr/month.

The fuel costs for diesel generator assume 30% efficiency, with

13% transmission loss; for the gas turbine at Moitaka 23%

efficiency. Distillate costs are estimates of the pre-tax wholesale

delivered prices.

ANNEX VIIPage 8 of 10

Forecasting the 1985 Import Bill

3. The product prices were forecast on the assumption that productprices grew at the same real rate as oil itself, which, given the considerablefixed refinery cost component, may overstate the future c.i.f. prices. Theassumed c.i.f. prices in constant 1980 US$ are shown below.

TABLE VII.7

1985 Product Price Forecasts(1980 US$/ton)

Central Low HighLPG 950 850 1050Avgas 550 430 800Mogas 480 420 500Avtur 440 390 500Kerosene 440 390 500Distill 400 370 470Fuel Oil 220 200 240

Coal c.i.f./TOE 75

These figures can now be used to project the import bill.

TABLE VII.8

1985 Forecast Import Bill(1980 US$ Million)

Central Low HighForecast

LPG 4.75 3.4 6.3Avgas 3.85 2.2 7.2Mogas 47.04 37.8 55.0Avtur 22.0 18.3 34.0Kerosene 9.68 6.6 13.0Distillate 136.4 85.5 195.0Fuel Oil 62.7 31.4 72.0Coal 0 16.4 0

Total 286 202 382

Projected exports of goods and services $1438 million (1980 prices)% share of fuel to exports 20%range (t 1 Standard Deviation) 14 - 27%

ANNEX VIIPage 9 of 10

1990 Petroleum Product Prices

4. The Bank's projected crude oil price rises by $40 (1980) per tonnebetween 1985-90. On the assumption that refining and transport margins do notrise in real terms, the projected 1990 product prices are all $50/tonne higherthan in 1985. The projected methanol price is based on scenario 2 of theBank-s Methanol Study which assumes that there is no real price increase formethanol after 1980, as opposed to Scenario 1, which assumes 2.5% p.a. realescalation. It is thus the more conservative assumption. Coal is assumed torise at 2% p.a. in real terms. The 1981 estimated delivered price to BCL was$48/tonne, and to Port Moresby $70/tonne.

The f.o.b. price of condensates is assumed to be the world market pricefor gasoline, less transport costs. The Bank-s Methanol Study projects the1990 gasoline price as (US$ 1980) $474/tonne, and hence condensates are valuedf.o.b. at $425/tonne. The price assumptions are summarised in the table below:

TABLE VII.9

1990 Price Assumptions1980 US $ tonne

LPG (import parity) 950Avgas 600Mogas 530Avtur 490Kerosene 490Distillate 450Fuel Oil 270Coal: BCL 60

Port Moresby 85Methanol f.o.b. 208Condensates f.o.b. 425

ANNEX VIIPage 10 of 10

TABL.E VII.l0

PROJECTED IM'PORT BILL FOR 1990 UNDER ALTERNATIVE SCENARIOS

Base Case Coal Case 'Business as IJsual'

Imports Vol. Value a/ Vol. Value a/ Vol. Value a/___ '000 tonnes $ million '000 tonnes $ million- '000 tonnes $ milliodT

LPG 00 7 7 7

Avgas 7 4 7 4 7 4

M4ogas L14 60 114 60 114 60

Avtur 64 31. 64 31 64 31

Kerosene 28 14 28 14 28 14 1

Distillate 333 150 346 156 352 158 U'

Fuel O11 12 3 14 4 398 107

Coal 445 28 678 43 0 0

Total Irnports 290 319 381

Exports

Condenisates 167 71 0 0 0 0

Metthanol 660 137 0 0 U 0

Total Exports 208 0 0

Net Inmports (US 1980 $) $82 millioii $319 million $381. million

a/ 1980 US$.

- 96 -

JOINT UNDP/WORLD BANK

ENERGY SECTOR ASSESSMENT PROGRAM

Reports Already Issued

Country Date No.

Indonesia November 1981 3543-IND

Mauritius December 1981 3510-MAS

Kenya May 1982 3800-KE

Sri Lanka May 1982 3794-CE

Zimbabwe June 1982 3765-ZIM

Haiti June 1982 3672-HA

Burundi June 1982 3778-BU

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