Report No 3882-PNG PapuaNew Guinea:Issues and Options in the EnergySector Public Disclosure Authorized
June 1982 Public Disclosure Authorized Public Disclosure Authorized
Reportof the joint ULMP/Mfdd BankEnergy Sector Assessment Program Public Disclosure Authorized This document has a restricted distribution. Its contents may not be disclosed without authorization from the Government, the UNDP or the World Bank. CURRENCY EQUIVALENTS
Currency Unit = Kina (K) 1 Kina = 1.5 US Dollar (1981) 1 US dollar = K 0.67 4 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 Equivalent DME Department of Minerals and Energy EDC Energy Development Corporation ELCOM Electricity Commission EPU Energy Planning Unit MMCF Million Cubic Feet MMCFD Million Cubic Feet per Day NEPC National Energy Planning Council PNG Papua New Guinea TCF Trillion Cubic Feet TOE 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 1.053 Avtur/Kerosene 0.78 43.5 1.038 Distillate 0.83 42.6 1.018 Residual Fuel Oil 0.97 40.4 0.965 Methanol 0.796 19.95 0.476 Coat1(Australian) 27.64 0.660
This report is based on the findings of an energy sector assessment mission comprising Messrs. N. B. Prasad (mission leader), Donald King, John Tatom, David Newbery and Ms. Huda Kraske which visited Papua New Guinea in November 1981. Secretarial assistance was provided by Beatrice J. Moses. The report 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/WorldBank Energy Sector Assessment Program. Finance for this work has been provided, in part, by the UNDP Energy Account, and the work has been carried out by the World Bank. This report has a restricteddistribution. Its contents may not be disclosed without authorizationfrom the Government,the UNDP or the World Bank.
TABLE OF CONTENTS
Page No
I- SUMMARY AND CONCLUSIONS.1...... -- 1
Energy Consumption ...... 2 Energy Forecast 1985 and 1990. 3 Deiand . 3 Supply. 4 Investment. 6 Energy Resources. 7 Electricity. 7 Oil and Gas. 9 Coal. 9 Geotherraal.10 Renewables ...... 10 Institutional Issues .12 Priorities for Action .13 Framework for Technical Assistance .14
II. ENERGY CONSUMPTION AND PRICING .15
Consumption Overview .15 The 1980 Energy Balance .18 Sectoral Pattern of Energy Consumption .18 Transport .18 Industry .19 Bougainville Copper Ltd (BCL).20 Non-Mining Industries .21 Agricultural Processin .22 Others .23 Agriculture .23 Households .23 Energy Pricing, Taxes and Subsidies .24 Electricity .24 Petroleum Products.25
III.. ENERGY RESOURCES. ISSUES AND OPTIONS ...... 27
Resource Overview .27 Electricity .27 Oil and Gas .31 Coal .34 Geothermal .36 Renewables .36 Woodfuels ...... 36 Ethanol .37 Biogas.39 Mini and Micro-Hydro .40 Solar Water Heating .40 Photo-voltaic Cells .41 Wind - Electric Generation .41 - ii -
TABLE OF CONTENTS (cont'd)
Page No.
IV. ENERGY OUTLOOK 1981-1990...... 42
Introduction ...... 42 Electricity ...... 42 The Transport Sector ... 45 Industry ...... 45 Other Sectors (Agriculture, Households, etc) ...... 46
V. INSTITUTIONS AND POLICY PLANNING .51
Introduction...... 51 The Geological Survey Department.. 51 The Energy Planning Unit .... 52 ELCOM .... 53 Bureau of Water Resources ... 55
VI. ENERGY SECTOR INVESTENT.. 56
ANNEXES
I: Energy Balances (1970 - 1990) . .59 II: The Electric Power Sector. 72 III: The Transport Sector .. 77 IV: PNG Hydroelectric Potential 83 V: Coal Occurrences in PNG . .84 VI: Organization Chart of the Department of Minerals and Energy . .85 VII: Consumption, Price and Import Cost Data 86
MAPS Twffl 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, is relativelywell-endowed with energy resources - hydro potential conservativelyestimated at 14,000MW,gas reserves (from six discovery wells) already estimated at a possible 1.5 to 5.0 trillion cu. ft. with large sedimentarybasin areas yet to be explored, a large biomass potential from its forests and good solar energy potential. Despite this, PNG is currently dependent on petroleum product imports for meeting most of its commercial energy needs. Petroleum products account for nearly 55% of all energy consumptionand 87% of all commercial energy consumption. Because of rising world oil prices and increasingdemand for petroleum products, the share of export revenue spent on oil imports has risen from about 3% in 1972 to an estimated 24% in 1981. The 1981 oil imports are estimated at US$209 million (CIF) and amount to over 8% of GNP, 30% of gross domestic investment,and 80% of net external assistance. Without major efforts by the government,energy imports will soon impose an intolerableburden on the economy.
1.02 The country's energy options are severely constrained by the small size of total domestic energy demand, as well as the geographical fragmentationof the market, which leads to high investmentand operating costs per unit of output. Careful planning is thereforeessential to determine the appropriateoptions available for substitutingimported petroleum products by indigenous energy sources. In recognitionof 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 objectivesand policies. The "White Paper" emphasized the role of renewablesin alleviatingPNG's energy problems, particularlyethanol for the transport sector (which consumes 45% of all petroleum products), wood pyrolysis for the industrial sector and solar water heating and photovoltaicsfor households,and EPU began promoting projects in these areas, many of which, following further analysis and feasibility studies, have since been abandoned or reduced in scope. More conventionalareas of activity tended to be neglectedand energy planning did not advance significantly. However, in late 1980 the EPU began to place more emphasis on the electricity sub-sector,where 40% of petroleum products are used, where multiple options are available for substitutingthe oil used in power generation and where severe and widespread operationaland financial difficultieswere being experienced. More recently, some attention is being paid to the prospectiveuse of onshore and offshore reserves of natural gas, to hydro developmentand to energy conservation. Energy planning, including analysis, policy and monitoring for the entire energy sector, covering all producer and user sectors and sub-sectors,still has to mature and in this report the mission makes various recommendationsfor developing and strengtheningthe energy planning process. In addition to institutional strengtheningthere is an urgent need to implement further studies to evaluate more fully the different energy supply options, especially those - 2 -
that will lead to firming up reserves of gas and oil, hydro and coal, so that decisions on which combination of energy sources is optimal to satisfy the medium-to-long-term demand of the various user groups can be taken in the near future.
Energy Consumption
1.03 The energy sector of PNG has developed alongside the various enclaves which have characterized the country's industrial, economic and urban development. The major enclave is Bougainville Copper, Ltd. (BCL), which is on Bougainville Island separated from the country-s major demand centers, and which consumes nearly 62% of all electricity generated and 40% of all petroleum products, either for power generation or as distillates for various mining and ore processing operations, such as crushing, drying, etc. Another copper mining enclave, Ok Tedi on the main Island of New Guinea close to the Indonesian border, is being developed and will start production in the mid-eighties. The country's urban enclaves, which have a large expatriate population whose pattern of living is set by modern developed country standards, consume most of the remaining electricity and petroleum products in the household, commercial and private transport sectors. Over half of the country's 32,000 household consumers of electricity in 1980 were in the two towns of Port Moresby and Lae, whose combined population is only 180,000 (6% of the total population of 3 million). The consumption of commercial energy in the rural sector (87% of population) is a meager 1.1% of the country's total commercial energy consumption.
1.04 Total primary energy consumption in 1980 is estimated at 1,143,000 tonnes of oil equivalent (TOE), of which 709,000 TOE (62%) is commercial energy, mostly in the form of petroleum products, and 434,000 tonnes (38%) is non-commercial energy, mainly fuelwood. Per capita consumption of total energy at 2.8 barrels of oil equivalent (BOE) is approximately the same as in middle income developing countries in Asia (Indonesia 2.2 BOE, Thailand 2.7 BOE, Philippines 2.8 BOE) though the pattern of consumption, as noted above, is substantially different.
1.05 PNG has become increasingly dependent on commercial energy in the past decade. Commercial energy consumption (mainly petroleum products) grew from 44% of total energy consumption in 1970 to 62% in 1980. 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 ten years. The increase in oil consumption is partly due to the use of oil for power generation and continuous operation of the gas turbine in Port Moresby, which was originally intended only as a stand-by, and to the start-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 two sectors, and especially the strategy adopted for future power generation among many available options (hydro, oil, gas, coal), will largely determine the growth of petroleum product consumption. Industry (including agricultural processing but excluding BCL) accounts for only 14% of electricityconsumption (of which nearly a third is from captive plant) and 6% of petroleum product consumption. Both industry and commerce have suffered from the unreliable public electricitysupply and have been forced to own and operate captive generating plants, mainly in the form of small diesel sets. In addition, there is also substantial suppressed demand for electricitybecause ELCOM, beset by its own managementand financial problems, has not been able to fulfill its role adequately as a public utility with the responsibilityof providing reliable power to all consumers at reasonable cost.
1.07 The pattern of final energy consumption in 1980 is given in Table 1.1 below:
Table 1.1 1/
PNG: Final 2/ Energy ConsumptionPattern, 1980 (000 tonnes of oil equivalent)
Total Commercial 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 on primary energy consumed. 2/ Net of transformationlosses of 236,000 TOE. 3/ Does not include petroleum products used for power generation equivalent to 248,000 tonnes of oil (40% of total petroleum products), included in the electricityproduced. 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 Tedi starts production. (By 1986 this mine might account for an additional 10% of GNP, suggesting that growth elsewheremay be below 4%.) This is comparable to growth over the past decade, during which energy demand grew steadily. Based on assumed sectoral growth rates, projectionsmade for BCL and Ok Tedi, and population growth rates, energy demand forcasts have been made for 1985 and 1990, and are summarized in Table 1.2 below: - 4 -
Table 1.2
Forecast Final Energy ConsumptionPattern for 1985 and 1990 (-000 TOE)
Electricity Petroleum Woodfuel Total
1985 Households 12 22 430 464 Industry 126 93 - 219 Transport - 297 - 297 Others (Agr. and Commerce) 15 8 70 93 Total 153 420i/ 500 1,073
1990 Households 17 28 473 518 Industry 172 122 - 294 Transport - 367 - 367 Others (Agr. and Commerce) 20 9 88 117 Total 209 526_/ 561 1,296 Growth Rates (%) 3/ 1980-85 8.5 2.5 2.9 3.4 1985-90 6.4 4.6 2.3 3.9 1980-90 7.4 3.6 2.6 3.6
1/ Does not include 392,000 TOE used for power generation,already included under electricity. 2/ Does not include 475,000 TOE used for power generation,already included under electricity. 3/ Historicalgrowth rates in final energy consumptionduring the seventiesare 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 for 1985 due to the short-leadtime available. However, the mission assumed that BCL may, by then, switch to coal-fired thermal plant (2 x 45 MW), instead of continuedreliance on fuel oil. The options available for 1990 are numerous and for the purpose of illustratinga few of these options and the magnitudes involved, three preliminarysupply scenarios have been quantified by the mission: (a) Case A (Gas) assumes that Pasca gas field will be developed and gas piped to Port Moresby for power -5-
generation and possibly methanol production while hydro is being developed at BCL; (b) Case B (Coal) assumes tht a 25 MW coal-fired thermal station will be built in Port Moresby, and BCL will switch to coal; (c) Case C (BAU) describes business as usual scenario with continued dependence on imported oil.
1.10 Condensed energy balances for 1990 appear in Annex I corresponding to the three scenarios outlined above and summarized below in 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)
Production Gas and Condensates 302 43 43 Hydro 2/ 304 197 243
Plus Imports Coal 304 447 - Petroleum 573 598 988
Less Exports Condensates -178
Total Commercial Energy Available 1305 1285 1274
Less Transformation losses (generation and other losses) -570 -550 -538
Total Final Commercial Energy Consumption 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 the production and export of methanol. 2/ Assuming 28% efficiency. -6-
Investment
1.11 Table 1.4 shows possible investment outlays in the energy sector for 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)
ELCOM Investment to 1985 2/ 130.0 130.0 130.0 Other investment 15.0 15.0 15.0 Port 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 49.5
Ok Tedi Diesel 18.0 18.0 18.0 Ok 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$30 million per annum. 2/ Does not include investment in a methanol plant (roughly estimated at US$300 million for a 2,000 tons per day capacity) consideredd as a possibility under Case A. 3/ Includes investment in Barikewa gas turbine and Rouna 4 ($71.0 m), Pauanda ($9.6 m), and Warrangoi ($49.4 m).
1.12 The direct balance of payments implications of these three scenarios are shown in Table 1.5 below: -7-
Table 1.5 Forecast Net Fuel Imports 1985 and 1990 (1980 US$)
1980 1985 1990 2/ A B C (Gas) (Coal) (BAU)
Imports of fuels in TOE 619 812 877 1045 988 Cost of fuel imports (million US$) 188.0 287.0 290 319 381 Less energy exports (million US$) 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 about US$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 from 1985-1990 (as assumed in Bank calculations), they will yield $1750 million in 1990 (1980 prices). Net imports of energy in 1990 range from $219-$381 million, or from 13%-22% of export revenue. If methanol is produced and exported as envisaged under Case (A) the economics of this option become extremely favorable. A 2,000 ton per day plant would be able to produce about 660,000 tons per annum. At about US$ 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 export earnings (which is below its share in 1969-70).
1.14 In sum, although larger quantities are imported in Case B than in Case C, the import bill is lower because cheaper coal substitutes for more expensive fuel oil used in Case C. Case A has an additional attraction in that it provides gas at Port Moresby for an export oriented petrochemical industry such as methanol. Although Case A (Gas) without methanol exports is attractive, it looks even more so with methanol exports. Thus, in spite of the fact that investment costs in Case A are the highest, such investment will result in drastically reducing the country's oil imports.
1.15 These scenarios have been done only for the purpose of illustrating the options available in the energy sector and the order of magnitude of energy imports and their costs. Detailed studies will be required to estimate the profitability or otherwise of the different components of these three scenarios, or other scenarios. In any event, potential investments in this sector will be dependent upon the availability of the resources necessary to finance these investments even assuming acceptable levels of profitability.
Energy Resources
Electricity
1.16 PNG-s largest energy resource is its hydroelectric potential with many potential hydroelectric sites, particularly on the Fly, Purari and Kikori Rivers flowing into the Gulf of Papua and the Musa River flowing - 8 -
into the Oro Bay. The total potential is conservativelyestimated at 14,000 MW (or nearly 5 kw per capita, one of the highest in the world). However, because of the fragmented nature of the country and limited demand in any one locality,development of large hydro resources has not been feasible and only some of the smaller run-of-riverschemes have been implemented. One difficulty in planning hydro developmentis the lack of stream gauging records for all except the largest rivers, and the mission recommends that urgent action be taken to introduce new gauging stations on potentialhydro sites for which no records exist. Attempts have been made to synthesizedata from general rainfall records, the characteristicsof similar streams, and from gauges installed in the relatively short period when any given project is under consideration. Hydro plants installedon the basis of such inadequatedata have not met expectationsand both minimum and average flows are seriously below the amounts designed for. Consequently,it has been necessary to provide thermal back-up (based on petroleum products) to deliver much of the energy required. Given the nature of the hydro schemes in operation and under consideration,thermal back-up will continue to be essential and should be included in all power sector plans.
1.17 Plans for future power generation must include some or all of the following:
(i) First, by expansion of existing hydro sites and a detailed investigationof other possible sites for feeding the Port Moresby/Ramugrids. The mission supports, subject to a detailed economic appraisal, ELCOM-s present plans to build another hydroelectric power station (Rouna 4) in the Port Moresby area since this 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 low firm plant factor, perhaps no more than 20% in dry years, which will be insufficientto supply the demand on the Port Moresby systems which has a load factor over 60%. At present, a gas turbine at Port Moresby is being used to meet the shortfall in dry years and some form of thermal back-up will continue to be needed.
(ii) Second, by the use of imported coal at BCL and Port Moresby. In the latter case, the mission strongly recommendsa reappraisalof the 25 MW coal-fired thermal plant proposed by consultantsC.T. Main, who were commissionedby DME to investigatethe options for power supply in the Port Moresby area.
(iii) Third, by use of natural gas resources, particularlythe Barikewa reserves for the Ramu grid but also, possibly, the Pasca/Uramureserves for the Port Moresby grid.
(iv) Fourthly, by using wood-wastes for power generation for the Ramu grid, which the mission considersworthy of -9
further examination,although the mission concurs with ELCOM's views that wood supplies in the Port Moresby area are insufficientto sustain even a 10 MW wood-burning plant on a long-term basis.
(v) Since other mining metallurgicalenclaves (besides Ok Tedi) are being consideredthe mission recommends that an inventory of all major hydro sites (over 50MW) be compiled and from this list preliminaryfeasibility studies of 3-4 selected hydro sites for such enclaves be started.
(vi) Finally, least cost studies of the various alternatives of expanding the ELCOM power system be continued over a longer (15-20 year) time frame.
Oil and Gas
1.18 Substantialexploration work has been done in the oil and gas subsector in the past fifty years, with mainly gas finds. Robertson Research's report, reviewing and catalogingall work done to date, is now ready. The Papuan Basin contains most of the gas found, mainly in two offshore wells (Pasca and Uramu) and four onshore wells (Barikewa,Iehi, Bwata and Kuru). On the basis of these discoveries,gas reserves are estimated to be 1.5-5.0 trillion cubic feet (TCF).
1.19 The pressing need for hydrocarbonfuels in the economy, coupled with the availabilityof gas, calls for a greater sense of urgency in using this valuable resource. As the situation now stands, the oil companieshave little incentive to develop the proven reserves for domestic use for power considering the small fragmenteddemand centers and degree of industrializationof the country, unless they can be associatedwith export-orientedindustries. The Governmentshould therefore:
(a) Require speedier exploration and appraisal of discoveries already made by oil companies as their work programs come up for periodic review under the terms of the licences already granted. If possible reserves are considered too small for export (as may be the case with Barikewa) considerationshould be given to providing incentives to the oil companies for developingsuch fields for the domestic market or alternatively,persuading them to relinquish the areas concerned.
(b) Carry out as soon as possible a gas utilization study on the onshore-offshoregas fields, mainly to establish the feasibilityof developmentof each of the individual gas fields, and evaluate a combinationof gas utilization options including: (1) a gas-fired power plant using onshore gas from Barikewa with transmissionto the Ramu System in the north and possibly to Port Moresby; (2) a - 10 -
pipeline from Pasca and/or Uramu to Port Moresby for power generation including recovery of condensatesand LPG; (3) methanol production for local and export markets. (4) an LNG plant (somewhere in the range of 75-500 mmcf/d capacity); and (5) ammonia/ureaproduction.
Coal
1.20 Coal occurrences have been found in the Morobe and Gulf Provinces and near Madang but no active follow-upwork has been considerednecessary to firm up reserves. They have generallybeen small deposits of low grade coal with seams dipping at moderate angles. From the meager data available, it is likely that technicallyrecoverable reserves exist in both Morobe and Gulf Provinces and that Pindiu, Purari and Hohoro areas may be the most promising. The viability of open cut mines in these areas should be examined for the purpose of power generation in Lae and Port Moresby as an alternative to the use of imported steam coal, after more geologicalwork and the firming up of reserves has been done. For this prupose the reserves required are modest (about 5 millin tons) and it is likely that external technical assistancewill be available. Geothermal
1.21 There are surface evidences of hydrothermalactivity in the form of seeps and geysers at temperature of 900/950C, particularlyin the Rabaul, Hoskins and Talasea thermal areas of New Britain and the Deidei and lamalele thermal areas of Fergusson Island. As electricity consumptionin these areas is small and there is no consumptionof steam for process purposes, there is no urgency in developing the potential, but some priority may be given to identifyingthe potential of the Rabaul thermal areas.
Renewables
1.22 PNG has had a comprehensiveprogram to produce energy from renewable sources. The main objective of the renewables program has been to substitute oil in the transport sector by ethanol, produced from cassava, sugarcane, molasses or sago palm. However, many of the projects originally included in the program were based on technology that had not been perfected; scarce funds have already been spent on experimental ventures with disappointingresults. The eventual potential for energy production from these sources might be immense, but their technicaland economic viability needs to be proven with minimal expenditures, particularlyin the context of potential developmentof oil and gas.
(a) Ethanol: Considerableemphasis has been placed on developing ethanol from biomass as a substitute for motor fuel. A cassava- based project at the Baiyer River is under developmentat present, and studies have been undertaken for at least four other projects (based on molasses, cassava plus sugarcane, sugarcane, and sago palm respectively). A potential six million - 11 -
litre/annummolasses-based project in the Ramu Valley seems economicallyattractive, but it is unlikely that any other new projects will prove viable. The economic justificationfor completing the Baiyer River Project is only marginal. EPU's published target in 1979 of 130 million litres per annum by 1990 has been recognized as unrealisticand has been reduced first to 36 million and more recently to 10 million. The Government should carefully review the economic justificationof any further investment in ethanol projects;
(b) Wood: Wood resourcesare tremendous (covering 40 million hectares) and fuelwood contributesabout 40% of total energy consumption. Nearly 95% of the fuelwood is consumed in households, the remaining 5% being consumed in the industrial sector, particularlyagricultural processing where it accounts for about 62% of all energy use It is expected that the consumptionof fuelwood will rise in proportion to the increase in population growth. The scope for its utilization in the industrial sector for heat and for power generation needs closer study. Attempts at using pyrolysis of wood wastes in industry at Lae have failed due to various technical difficulties. Gasificationhas only been attempted on an experimentalscale. Studies for the utilizationof the considerablewood wastes through wood gasificationand steam generation should continue to be made. The possibilityof running small diesel generating sets with wood gas in remote areas needs to be pursued as the technology is fairly well proven. Wood burning conventional power generationhas been considered by ELCOM and rejected, but may be worth a second look, particularlyat Lae-Bulolo.
1.23 With respect to other renewables:
(i) The mission supports EPU's decision that no further investment in biogas should be made. In any event, the biogas plant in Lae has failed and the one installed at Waghi Mek Coffee Plant is inoperable due to technical difficulties.
(ii) The mission also supports EPU's decision to halt further investment in pyrolysis due to the technical difficulties encounteredin using the wood wastes in the Lae area.
(iii) Solar water heating has had great success in residential and commercial buildings and is economicallyviable. The mission commends the measures taken by Government for this purpose, especially the provision of tax incentives for the installationof solar water heaters.
(iv) Photo-voltaiccells are very expensive and are not economicallyviable at present given the very low consumptionof kerosene for lighting purposes in rural -12-
households. As the cost of cells declines in the future with improved technology,further investment in them for other applications,particularly in telecommunications, may become more attractive,and therefore the current, relativelylow, levels of funding may continue.
InstitutionalIssues
1.24 In the petroleum subsector, the Geological Survey Division within the Department of Minerals and Energy has responsibilityfor technical advice on all matters concerningoil and gas, coal and geothermalenergy. However, the same Division is also responsible for similar activities in the mining sector, which due to its importance in the economy, tends to receive higher priority, leading to some neglect of the energy sector. A small group of expatriatesand PNG nationals, all geologists and geophysicists,look after both minerals and oil and gas. There is no staff experiencedin petroleummatters. In view of the importance of oil and gas, the Geological Survey Division ought to be strengthenedby drawing on outside expertise to oversee the implementationof the Government'sexploration policies and eventually, as delineationof reserves progresses and commercial discoveriesare made and developed, the option of having a separate agency for oil and gas should be considered.
1.25 In the power sector, mismanagement,lack of planning and, until recently, tariffs that did not reflect cost, were the primary cause of ELCOM's financial difficultiesand the power shortages in the late 1970s. The situation further worsened in 1980/81 due to failure of the hydro system 1/ and the larger reliance on diesel-fuelledturbines. However, it is only fair to point out that some of the trouble originated from policies and actions taken before independence,and despite attempts aimed at speedy improvement,it has been difficult to catch up. In addition to a new General Manager, who has been recruitedfor a five-year contract, four technicalstaff from Montreal Engineering Inc., have been hired for three years to help run ELCOM, and this is likely to improve matters.
1.26 The Energy Planning Unit should continue to be part of the Department of Minerals and Energy. However, its size, role and emphasis should be redefined as follows:
(i) EPU should function as an overall energy study and planning agency for all the energy subsectors including oil and gas, power, and coal, and not focus mainly on renewable energy planning. In order to make realistic demand forecasts for all energy subsectors,EPU should work closely with ELCOM and the various agencies dealing with the primary energy subsectorsand the Forestry
1/ Exemplified by turbine breakage, siltation, drought, etc. - 13 -
Office of Department of Primary Industries (DPI). EPU's expertise should be diversifiedso that it can handle these new responsibilitiesas well as effectivelymonitor energy policies, programs and conservationmeasures.
(ii) In order to emphasize the importance of overall energy planning, the promotion and implementationof renewable energy projects and conservationmeasures could be entrusted to a separate unit under the Planning and Policy Division.
Priorities for Action by PNG
1.27 Among the various recommendationsmade in this report, the mission considers that priority should be given, or continue to be given, to:
(a) Inducing the oil companies drilling in PNG to accelerate their explorationactivities in an effort to firm up reserves of oil and gas and reach agreements on the developmentof already discovered gas fields (paras. 1.19 and 3.24).
(b) Completion of a gas utilizationstudy on the onshore - offshore gas fields (paras. 1.19 and 3.22).
(c) Urgent reconsiderationby ELCOM of a 25 MW coal-fired thermal plant for Port Moresby and, if viable, developmentas soon as possible (paras 1.17 and 3.11).
(d) Creation of a group of outside specialistsfor oil and gas within the Department of Minerals and Energy to emphasize and give a greater sense of urgency to more intensive exploration activities by the oil companies and monitor trends and operations in the subsector (paras. 1.24 and 5.03).
(e) Redefinitionof the role of EPU within DME so that it can function as an overall energy planning agency, and creation of a separate unit for the implementationof renewable energy projects and conservationmeasures (paras. 1.26 and 5.06).
(f) Confiningwork 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 feasibilitystudies for possible use by metallurgicalenclaves (paras. 1.17 and 3.14). - 14 -
(i) Finally, least cost studies of the various alternativesof expanding the ELCOM power system be continued over a longer (15- 20 years) time frame (paras. 1.17 and 3.16).
Framework for TechnicalAssistance
1.28 To assist the Government in implementingmany of the recommendationsmade above, the mission strongly recommends that technical assistancefinanced by the Bank, ADB, UNDP or other donors be made available to carry out the following urgently needed activities:
(a) US$1-1.5 million gas utilizationstudy on the onshore-offshore gas fields, possibly within the context of the on-going petroleum explorationproject;
(b) US$1-1.5 million for an inventoryof major hydro sites and preliminaryfeasibility studies of 3-4 large hydro sites to determine their potential for use by an enclave metallurgical operation;
(c) US$1.0 million for financingabout 75 new gauging installations on small hydro sites for which there are no flow records;
(d) A series of wood and wood-waste utilizationstudies;
(e) Delineationwork on coal reserves for domestic use in thermal power plants; and
(f) Institutionalstrengthening for EPU to enable it to function as an overall energy planning agency. - 15 -
CHAPTER II
ENERGY CONSUMPTIONAND PRICING
ConsumptionOverview
2.01 Total energy consumption in PNG in 1980 is estimated at 1,143,000 tonnes of oil equivalent (TOE) of which 709,000 TOE (62%) is commercial energy and 434,000 TOE (38%) non-commercialenergy, mainly woodfuel. Per capita consumptionof total energy is approximately2.8 barrels of oil equivalent (BOE), which is the same as in middle income developingcountries in Asia (Indonesia 2.2 BOE, Thailand 2.7 BOE, Philippines2.8 BOE). Annexes I and VII offer detailed historical data on energy consumptionand prices in PNG while Table 2.1 shows consumption trends in PNG during 1970-80.
Table 2.1
Primary Energy Consumption,1970-1980
Consumption (O000 TOE) 1970 1975 1980
Commercial 269 567 709 Non-commercial(woodfuel) 343 389 434 Total 612 956 1,143
Percentage Share (%)
Commercial 44 59 62 Non-commercial(woodfuel) 56 41 38 Total 100 100 100
Energy Intensity 1/
Total Energy/GDP .53 .68 .80 CommercialEnergy/GDP .23 .28 .50 Final CommercialEnergy/GDP .19 .27 .33
Average Growth (% p.a.) 1970-75 1975-80 1970-80
Commercial 16.2 4.6 10.2 Non-commercial(woodfuel) 2.5 2.2 2.4
Total 9.3 3.6 6.4
1/ Energy intensity is the ratio of energy consumptionin TOE to GDP in '000 1977 Kina. GDP estimates in 1977 prices are: 1155 million Kina in 1970; 1406 million Kina in 1975; and 1430 million Kina in 1980. - 16 -
2.02 While decliningas a proportion of total consumption,woodfuel accounted for an estimated38% in 1980 as against 41% in 1975 and 56% in 2970. In absolute terms, woodfuel consumptiongrew at 2.4% durin'gthe seventieswhich is close to PNG's population growth rate of 2.3% p.a.
2.03 Commercialenergy consumptionincreased from 44% of total energy consumptionin 1970 to 62% in 1980, i.e. at a growth rate of 10.2%. Since 87% of all commercial energy consumed comes from petroleum (the rest being supplied by hydro) this in turn reflects an increased dependenceon oil imports. Petroleum consumptionfor power generation has increasedfrom 18,000 TOE in 1970 (30% of electricity)to 248,000 TOE in 1980 (76% of electricity),i.e. at a rate of 30% p.a. At the same time consumptionof petroleum products in the transport sector increased from 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 9,000 TOE to 11,000 TOE.
2.04 GDP grew from 1155 million Kina in 1970 (1977 prices) to an estimated 1430 million Kina in 1980, i.e. at 2.2% p.a. (whereas populationgrew at 2.3%), and per capita GDP therefore stagnatedduring the decade. Despite this, energy consumptionhas continued to grow faster and the ratio between energy consumptionand GDP has therefore increased,making PNG more energy intensive.
2.05 The most dramatic increase in energy consumptionoccurred in 1970-75 when the BougainvilleCopper Mine (BCL) started production. BCL imports oil to generate electricitywhich is used primarily to produce concentratefrom low grade ore. Table 2.2 shows the sectoral consumption of primary commercial energy including and excludingBCL, which consumes a third of primary commercial energy. - 17 -
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 47 Mining (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 19 Others (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 greater consumption of electricity and kerosene in households, and of fuel for electricity and transport. (For a discussion of the development and organization of the electric power sector, see Annex II). This takes place mainly in urban enclaves (such as Port Moresby and Lae) by expatriates and by the indigenous middle income class whose life-style follows the expatriate model. 1/ The growth in public employment has encouraged rural to urban migration and has generated a rapid growth in urban population (7.5% p.a.). This has also led to higher energy consumption per capita, while the growing penetration of roads into the rural areas has led to a growth in energy used in transport.
1/ It is estimated that 59% of domestic electricity consumption in Port Moresby in 1980 is consumed by 3,400 expatriate households, while 52% of cars and station wagons in 1978 belonged to expatriates. - 18 -
The 1980 Energy Balance
2.07 The 1980 energy balance, includingwoodfuel consumption,is given in Annex I (Tables 1.4 and I.5) and is summarizedin Table 2.3 below. Of the total primary energy consumed, 524,000 TOE or 46% was indigenousand the remaining 619,000 TOE or 54% was imported petroleum. 83% of the indigenousenergy productionwas woodfuel and the remainder was 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 ConsumptionPattern in PNG in 1980 ('000tonnes of oil equivalent)
Electricity Petroleum 3/ Woodfuel 4/ Total
Households 10 18 386 414 Industry 80 73 48 201 Transport - 275 - 275 Others (Agr. & Commerce) 12 5 17 Total 102 371 434 907
1/ Annex I (Tables I.4 and 1.5) contains data on primary energy consumed. 2/ Net of transformationlosses of 236,000 TOE. 3/ Does not include petroleum products used for power generation equivalentto 248,000 TOE, included in the electricity produced. 4/ Estimated.
Sectoral Pattern of Energy Consumption
Transport
2.08 Estimates of consumptionof fuel in the transport sector and its growth are given in Table 2.4. - 19 -
Table 2.4
Transport Fuel Consumption (000 TOE)
Vehicle 1/ Gasoline Distillate 2/ Total Registration (Road & Marine) OOOKL OOOTOE OOOKL OOOTOE OOOKL OOOTOE
1970 34,667 76 58 75 63 151 121 1971 36,163 91 70 111 93 202 163 1975 41,430 113 88 100 84 213 172 1980 47,436 (1979) 117 90 148 125 265 215
1/ Data from PNG StatisticalBulletin, March 25, 1981. These members include motorcyclesand tractors also. The figures for 1971 and 1980 excluding these two categories are 33,420 and 42,865 respectively 2/ Estimated as a residual after deducting fuel consumptionin power generation and industry.
2.09 The growth rate of vehicle population excludingmotorcycles and tractors has been around 4% between 1971 and 1980, whereas the transport fuel consumptionhas grown at only 3%. These estimates suggest that fuel consumptionper vehicle has been falling over time, a response both to steeply increased gasoline prices and introductionof smaller, more- efficient cars. This ratio might have declined further were it not that maintenance and depreciationcosts are relativelymuch higher than fuel costs 1/. Figures for distillate consumption (84% of which is assumed to be used for road transport)show the same pattern of decline in fuel consumptionper vehicle, although the effect has been less marked probably because trucking demand is generally less price elastic than personal travel demand. Further discussion of the transportsector appears in Annex III.
2.10 Although transport is the major user of petroleum products, it is the sector for which there are the fewest alternativenon-oil based fuels. It is also the sector in which demand is likely to increase because of increasingurbanization and rural development.
Industry
2.11 The largest single fuel using industry is BougainvilleCopper
1/ Some evidence for this is provided by the high attrition rate of vehicles and their short life. On average, it appears that cars last only about 4 years and hence deteriorate at twice or more the rate common in industrializedcountries. - 20 -
Ltd. (BCL) which in 1980 consumed 35% of total primary commercial energy and 40% of the petroleum products in the country. The non-mining industrial sector can be convenientlydivided into two; the processingof agriculturalproducts, and a heterogeneouscollection of other industries. Of the 155,000TOE final commercialenergy consumptionin the industrial sector (Table 2.3) BCL consumes 101,000TOE (65%), while agriculturalprocessing companies and the other non-mining industries consume the other 35%. These three subsectors are discussed below.
BougainvilleCopper, Ltd.
2.12 In 1979 and 1980 BCL consumed 35% of total primary commercial energy and 40% of petroleum products (by thermal content). Most of this fuel was residual fuel oil used in power generation,though appreciable quantities of distillatewere consumed by mobile mining equipment and some diesel was used for drying the concentrate(1.5 million litres p.a.).
2.13 Currently some 100,000 tons of ore per day are crushed, and another 100,000 tons are moved but discarded. As the ore grade declines copper production can only be maintained by increasing the volume of ore handled. As the ore volume increases, more ball mills are required, and this in turn generates further demands for electricity. In 1979 and 1980 the maximum demand was 109 MW; this is forecast to grow to 159 MW by 1984. Current generating capacity is 135 MW (3 x 45 MW) residual fuel oil fired thermal generators,which will not be adequate to meet the expected growth in demand. Two major studies of the options for electricitygeneration done for BCL (by Bechtel and Minenco Pty.) have been completed,both of them recommendinga shift to coal fired thermal plants. However, BCL's management has decided instead to install two gas turbines with a combined capacity of 45 MW for peaking, to be commissionedin 1982, as a stop-gap while decisionson hydro power, and the possible switch to coal firing or new coal-fired generating plant, are made. Negotiationsbetween the mine and the governments (local and national) on extending the mining license are still not finalized and BCL management is in a "wait-and-see"state of mind.
2.14 Although the hydro option is limited to run-of-river1/ with a low flow of 20 MW, and maximum flow of 60 MW, this alternative is attractive to BCL if financed by the Government.However, it would entail continued dependenceon fuel oil (or coal, if a switch is made) for the balance of the power generation. Coal import prices are $35-48/tonne(or $54-$73/tonneof oil equivalent),substantially below the import price of residual fuel oil in 1981 ($220-$243/tonneof 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) in 1981, based on an Australian East Coast price of K19-22/tonneand shipping costs of K6-9/tonne in 25,000 dwt ships or K4.6-6/tonnein 50,000 dwt ships, and an exchange rate of $1.5 per Kina. I - 21 -
Given BCL's objective of increasing copper production, the mission recommends that the decision to switch from oil should be expedited, and work advanced on evaluating the possibilities of using a medium-sized hydroplant 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, fuel and light for manufacturing industry for 1978 (see Table 2.5) 1/.
Table 2.5 Values of Output and Cost of Power, Fuel and Light 1978
Cost of Power, Value of Energy Fuel & Light Output Intensity (K million) (K million) (Percent)
Sectoral Breakdown
Food, drink, tobacco 3.8 184.1 2.1 Wood 2.0 45.5 4.4 Basic metals 2.8 60.1 4.7 Other 3.2 80.4 4.0
Total 11.8 370.0 3.2
Regional Breakdown
South 2.9 92.1 3.1 Highlands 1.6 60.7 2.6 Morobe a/ 2.2 98.3 2.3 Other 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-intensive electricity, gas and water sectors. - 22 -
Using a weighted average cost of fuel for 1978, the mission estimated that total fuel use in manufacturing in 1978 was 51,000 TOE which is close to the 49,000 TOE estimated by EPU for commercial fuel use by the industrial sector (excluding BCL) in 1976/1977. This also constitutes only about 10% of total commercial energy consumption.
Agricultural Processing Industries
2.16 Energy costs are quite important for agricultural processing industries for two reasons. Firstly, as these are export industries, they are more cost sensitive than non-traded products because of fluctuations in primary commodity prices. Second, they are often quite energy intensive. As a result, they have undertaken more substitution away from oil to burning wood than other sectors. Table 2.6 summarizes the importance of each crop for the balance of payments, the proportion of its f.o.b. value accounted for by oil costs where oil is used, and the total estimated quantity of fuels used. From this table it can be seen that oil accounted for 25% of the total energy used for all crop drying and amounted to 38% on an oil equivalent basis. At current oil prices it has become commercially attractive to replace oil by biomass - wood, coffee and copra husks, etc., and the share of oil in total fuel use is expected to continue to fall. This is definitely a very impressive example of inter-fuel substitution taking place in response to price factors. It is also seen that the burden of fuel costs varies from crop to crop, from a very low 1.2% in coffee processing to 38% for tobacco dried in small barns with kerosene.
Table 2.6
Fuel Use in Agricultural Processing Industries and 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 7.1 Cocoa 28.7 48.4 5 2.3 5.3 10.6 Copra 91.6 24.7 15 2.5 9.8 18.6 Tea 7.9 8.5 10 1.4 1.4 4.5 Rubber 4.0 3.8 .. - 2.0 4.0 Tobacco 0.1 0.2 15-38 1.8 0 0 Coconut oil 33.6 14.9 5 2.5 0 0 Timber 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. - 23 -
Other Industries
2.17 Between 1979 and 1980 there has been a considerablefall in heavy fuel oil demand, and some switch to woodfuel. Estimated oil consumption in industries other than agriculturalprocessing in 1980 is about 22,000 TOE. Consumptionfigures and patterns in the total industrial sector (excluding BCL) make it clear that most industry in PNG is not very energy intensive, with energy costs amounting to 3.2% of gross output (Table 2.5) or about 6.4% of value added. This compares with energy costs in 1978 in BCL of 7.7% of gross output, or about 12% of value added, and energy costs in agriculturalprocessing of 4.3% of gross output (Table 2.6).
Agriculture
2.18 Agricultureaccounts for about one third of GDP, but a very small fraction of total energy use. Its direct demand for commercial fuel is estimated at only 3,000 TOE in 1980, less than 1% of total final commercial energy consumption. This estimate is based on the small number of tractors in the country (1700), many of which are used for non- agriculturalpurposes. The processing of agriculturalproducts is, in contrast, quite energy intensiveand has already been dealt with above (para. 2.16); agriculturalproducts also require transport, so that indirect energy consumptionuse is considerablyhigher. Although agriculturaloutput stagnated in the 1970's, it is forecast to grow at about 3.5% p.a. during the 1980's. On this basis, tractor usage is projected to increase, but direct energy consumptionremains very small.
Households
2.19 As noted earlier (para. 1.03), PNG is characterizedby the 'enclave'type of development,where the urban enclaves account for nearly all the commercial energy consumptionand the rural areas are largely dependent on non-commercial energy. As can be seen from Annex I, total energy consumption in the household sector in 1980 is estimated at 416,000 TOE, of which 386,000 TOE (93%) is from non-commercialsources, mainly woodfuel, and only 28,000 TOE (7%) is from commercial sources. Petroleum products (mainly kerosene) account for 18,000 TOE and electricity for 10,000 TOE of the commercial energy used in households. The rural population is estimated at 2.6 million (87% of total) and it consumes 371,000 TOE (363,000TOE non-commercialand 8,000 TOE commercial). The urban population at 0.4 million (13%), consumes 45,000 TOE (25,000 TOE non-commercialand 21,000 TOE commercial). Per capita consumptionof total energy in the rural areas is therefore estimated at 0.14 TOE per annum, while in the urban areas it is lower, at 0.11 TOE per annum reflecting the greater efficiency of use in the urban sector which relies on commercial fuels to a greater extent than the rural sector. Hlowever,per capita consumptionof commercial energy in the rural sector is 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 the rural sector is done with woodfuel and the small amount of commercial energy used is in the form of kerosene for lighting.The per household consumptionof fuelwood comes to approximately6.6 kgs per day - 24 -
and this is close to the figure for other developingcountries (such as Indonesiawhere 6 kgs per household per day is consumed in rural areas). In the urban sector, kerosene, electricityand woodfuel are used for cooking and electricityand kerosene are used for lighting. 2.20 The household consumptionof kerosene for lighting in the rural areas comes to nearly 22.5 litres/yearwhich is substantiallylower than the household consumption in middle income developing countries and closely approximatesthe level of consumption in the poorer developing countries. This is one of the reasons why rural electrificationprograms are not likely to be viable in the rural areas of PNG unless they are combined with the introductionof productive industries.
Energy Pricing, Taxes and Subsidies
Electricity
2.21 No change was permitted in electricity tariffs from 1975 until 1980, despite the increase in cost of fuel by nearly 100% and operating expenses by 50%, a major factor which has led to ELCOM's recent financial difficulties. A tariff study funded by the Asian Development Bank (ADB) was received in 1981 and tariffs were raised three times during the period November 1980 - November 1981 by a total of 69%. Table 2.7 shows tariffs effective as of January 1, 1982.
Table 2.7
Tariffs Effective from January 1, 1982 (toea per kWh)
t/kWh USQ/kWh
(a) Category I Port Moresby, Ramu, Kieta/Arawa All kWh 11.5 17.25
(b) Category II 1/ First 50 kWh 11.5 17.25 Balance 15.7 23.55
(c) Category III 2/ First 50 kWh 11.5 17.25 Balance 26.0 39.00
Minimum monthly charge K 2.00 (US$3.00)
1/ Category II refers to small financiallyself-sustaining, networks (Annex II). 2/ Category III refers to very small ELCOM stations (Annex II).
2.22 The present tariff structure together with the introductionof the 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 how production costs are expected to decline with the installationof the new more efficient gas turbine in Port Moresby:
Table 2.8
Elcom Productionand 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 Moresby Old Gas Turbine 0.44 23 24 10.6 2.1 (13) 14.6 New (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 considerableout-cry against the sudden sharp increase in tariff levels, coupled with increasingcomplaints about the quality of service. Commercialand industrialconsumers are, therefore, increasinglytending to provide their own diesel generation. The high electricity tariffs are necessary to offset ELCOM's high operating costs which have resulted partly from increased reliance on imported oil. Therefore, it is essential that other, less expensive,fuels be utilized for power generation,before any further cost escalations lead to tariff increases.
Petroleum Products
2.23 In the recent past the Government has subsidizedmotor spirit, distillate,and lighting kerosene in remote areas, ensuring that prices were no higher than 12 toea/litreabove main port prices in 1977/78, and somewhat higher in later years (16 toea/litrein 1981). The cost of this subsidy scheme was estimated at K1.6 million for 1977/78, and possibly a similar amount in 1979/80. In the General Price (AmendmentNo. 64) Order of November 3, 1981, the maximum selling prices were further raised so that subsidies were only payable at a few very isolated locations (mainly in West Sepik). Prices are revised on a monthly basis, on the basis of submissionsmade by the distributingcompanies (BP, Shell and Mobil) to the Ministry of Finance. Table 2.9 shows maximum selling prices for petroleum products as of November 1981. - 26 -
Table 2.9
Maximum Selling Price of Petroleum Products as of November 1981
Motor Spirit Distillate Kerosene t/litre US$ gallon t/litre US$ gallon t/litre US$ gallon a) Retail price in Port Moresby 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 maximum inland price with- out subsidy 91.2 5.47 94 5.64 99.2 5.95
2.24 While the previous, more generous subsidies reflected the Government's redistributive and egalitarian aims, they were financially burdensome. The present policy reflects the new awareness of the importance of efficient rather than equitable pricing, a principle also extended to electricity pricing. The most important remaining subsidy is that accorded to ethanol 1/, which, at the proposed Baiyer River Plant, would escape the import dufty on gasoline, yet sell at the post-tax inland gasoline price. At best, this subsidy should be regarded as a subsidy for research and development, to ascertain the viability of an ethanol industry in the Highlands, which the project may produce. As such, it would 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 tax falls 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 bulk retail (at service stations) and local markets. In the recent Budget, taxes on distillates were increased while there was no increase in taxes on kerosene. The mission considers that it is necessary to preserve some consistency in the taxes on distillate and kerosene to prevent inefficient substitution between them.
2.27 In conclusion, the current pricing and tax policies for oil products appears to be consistent with other energy policies, and recent changes made in the 1982 Budget have increased the emphasis placed on efficiency in pricing.
1/ No ethanol is currently produced in PNG, yet this subsidy is intended to promote ethanol production. - 27 -
CHAPTER III
ENERGY RESOURCES: ISSUES AND OPTIONS
Resource Overview
3.01 Papua New Guinea is well endowed with diversifiedenergy resources. The largest resource is the hydroelectricpotential created by the mountainous topographyand generally heavy rainfall, particularly on the Fly, Purari, and Kirori rivers flowing into the Gulf of Papua and the Musa river flowing into the Oro Bay (See Map 16281). The total hydro potential is estimated at 14,000-21,000MW 1/ (or nearly 5 to 7 kw on a per capita basis, one of the highest for any country in the world). Moderate size gas discoverieshave been made, both onshore and offshore, with gas reserves conservativelyestimated at 1.5 - 5.0 TCF and condensatesat over 60 million barrels. However, consideringthe large area underlain by sedimentaryrocks with potential for petroleum and natural gas, past explorationhas been quite modest and these hydrocarbon resourcesare essentiallyunevaluated. Oil companieshave not acceleratedtheir drilling nor has the government induced them to do so until recently. PNG also has a large biomass potential from its extensive forests, which cover nearly 40 million hectares, of which less than 10% are being used for logging operations. The country has surface manifestationof geothermal energy. Coal occurrenceshave been reported in the Gulf Province and near Lae. The country's resource base provides a wide variety of long-termoptions for its energy planners. These are discussed in the followingsections. Electricity
3.02 The public power sector is in a state of disarray and at present there is only limited prospect for improvement. The situation is attributedto weak management, poor planning and poor operations and maintenance. The large increase in oil prices and the series of problems stemming from unexpectedlypoor hydrologicalconditions affecting the hydro plants have accentuatedthe problems.
3.03 ELCOM and its consultant, Charles T. Main, agree on a probable load growth averaging approximately7% up to the year 2000. Given the country's current stage of development and its potential for further development,7% at first sight appears low; however, the following factors would suggest it may not be so: (i) no accelerationof GNP growth is anticipated;(ii) tariffs have become very high in absolute terms, to the point that they will likely inhibit demand growth in the household and industrialsectors;(iii) a considerablenumber of commercialand industrialconsumers have installed their own generating facilities, because of ELCOM's unreliable service and load shedding,and others may do so 1/; (iv) new mining loads of any large size are not included in the
1/ Installedhydro capacity in PNG is about 100 MW. - 28 -
forecast since they will also have captive plants.
3.04 Although there are many potential hydroelectricsites (Annex IV), the fragmentednature of the country, and limited demand in any one locality,mean that the developmentof large hydro resources is only possible if it is to support power intensive industry,mainly metallurgical. This is likely, although not during the eighties due to the long lead times required by such ventures. Several American and Japanese aluminum companies have shown interest in utilizingPNG's hydro resources.
3.05 A particular difficulty in planning hydro developmentis the lack of stream gauging records, particularlyfor the small rivers. The large rivers have been given more attention and gauging informationis available or, in some cases, is in the process of being obtained. Some identificationsurveys of potential small hydro sites have been made employingelevations based on profiles obtained from air photography,the formula developed by ADB based on average rainfall and head, and a helicopter sweep/land touchdown of site. The reports for some of these surveys include a preliminaryplan for each station identified together with river flow characteristics. This gives a false authenticityto informationthat is highly uncertain.
3.06 Hydro plants installed on such a basis may not meet expectations,and minimum and average flows may be seriouslybelow the amounts designed for, particularlyin dry years. The provision of such facilitiescarries with it the implicit premise that thermal back-up is required and in general, that thermal capacity may have to provide much of the energy, perhaps the bulk, representingthe difference between the plant factor of the hydro stations and the system load factor.
3.07 Both ELCOM hydro stations under construction,Pauanda and Warangoi (para. 3.08), fit this profile as there were no river gauging records for either. For Warangoi, which is a very high unit cost project, it is recognized that supplementarydiesel will be necessary and it is still not known how much diesel energy on average will have to be generated annually. The mini-hydro stations (Tinputz,etc.) also lacked gauging records. For the Naoro-Brown potential developmentthere is a 23 year gauging record, but located below the junction of the two rivers. For the Tua and Oreba sites, present gauging informationis 3 years for one, about 13 years for the other. Rouna had a 23 year gauging record, but actual experiencesuggests the data may have been unreliable,or simply that for watersheds of its small size, in such mountainous terrain, gauging records are not as reliable for predictinghydrological performanceas they are for larger rivers. There is also doubt that the hydrology of Ramu river in the north (6 year gauging record)would be adequate to support the five unit plant for which it was designed (three units have already been installed). Therefore, the mission strongly - 29 -
recommends investment in about 75 gauging stations on small rivers (with a potential of 10-15 MW each) throughout the country.
3.08 The 1980-90 developmentprogram of ELCOM has been in a continual state of flux for the past 3-4 years. Several major projects of long standing have been dropped and others delayed as perceptionschanged. The present status is:
(i) Pauanda hydro (12 MW) on the Ramu system is under constructionfor commissioningin 1984; (ii) Warangoi hydro (10 MW) on the Rabaul system is under constructionfor commissioningin 1983;
(iii) Rouna 4 (13.5 MW) for Port Moresby is in principle committed -- provided the investigation underway concludes that the stability of the left bank, on which the.flume would be built, is, or can be made, satisfactory.
(iv) For Port Moresby, consultantshave recently identified the 42 MW Naoro-Brown river site. A feasibilitystudy for the Brown River Basin has been commissionedby ELCOM.
3.09 As to the option of using gas for electricitygeneration for the Ramu system, ELCOM hopes to have the Barikewa natural gas field in the Southern Highlands developed, gas piped about 6 km.to a gas turbine set, and a 160 km transmissionline built to the Ramu grid at Mt. Hagen. Very preliminarycost estimates, including an 18 MW gas turbine, are about K 23 million (US$34 million). Part of the transmissionline would be through very rugged country with only helicopter access for construction. The precise economics of the scheme would depend on the well-head price of gas 1/. This is an option that should be evaluated irrespectiveof the results of Barikewa 2 as the gas reserves required for 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 because it would provide firm base load, which could be increasedas required by additional gas turbine installationsat Barikewa. All of the four hydro schemes listed in para. 3.08 are run-of-riverwith firm plant factors likely to be well below the systems energy needs. Their addition will increase the imbalance between the energy required and that generated on a firm basis, particularlyin dry years to which these streams are so vulnerable. 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/BOE would be K3.5/1000 cubic feet). - 30 -
until they are provided with a substantialbase load generating plant. The Pasca gas/condensatediscovery some years back, located80 km off- shore in the Gulf of Papua and 250 km up the coast northwestof Port Moresby, might, if exploited quickly, provide thermal generation to the Port Moresby area. A brief desk study by the World Bank's Energy Department indicatesthat the economics of such an undertakingmight be quite favorableyielding an economic rate of return of 20%. The economics of such a project are further improved by the production and export of methanol.
3.11 In any case, cheap baseload power facilitiesare needed as soon as possible. Therefore,ELCOM should pursue the possibilityof installinga coal fired conventionalsteam 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 substantially lower than the hydro in prospect, and would provide base load. Even larger units of standard size might well be economic,although the additional capacity could be somewhat premature. The main point is that the two major systems, i.e. Port Moresby and Ramu, have to be relieved of the necessity of continuing to burn high cost distillates in diesel engines and gas turbines in increasingamounts in the future, due to hydrologicaluncertainties associated with small run-of-riverhydro stations.
3.12 The gasificationof woodfuels in large gasifiers suitable for direct use in gas turbines is still in the developmentstage; therefore, the possibilityof gasifying sawmill wastes at Lae or elsewhere on a sizeable scale will have to wait. However, plans to use the gasification process to fuel small diesels (up to 500 kw) maybe pursued as technology for this purpose is adequately developed. The sawmill wastes could also be used for thermal power generation using specially-designedboilers
3.13 The Government s cautious approach to rural electrificationand mini-hydro seems reasonable. It appears that photo-voltaiccells might come to have limited commercial application,predominantly for telecommunicationbut also possibly for lighting in villages, and in some other places for fans and pumps where the consumersare affluent. The outlook for wind generatedpower, however, does not appear promising on the basis of availablemeteorological data.
3.14 Besides Ok Tedi located in the westernmostpart of the New Guinea Island near the Indonesiaborder which is being developed for gold and copper concentrates,based mainly on hydro power, other sites which might offer opportunitiesfor similar, industrial and mining development include: (a) hydro sites on the Purari River mainly for a metallurgical enclave 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 MW thermal station is under constructionin 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. - 31 -
nickel and cobalt mining, and (c) Porgera in Enga Province for gold mining. None of these potential developmentsare firm prospects at this stage. If one or more should eventually proceed, it may supply power to ELCOM. This might be of importance to the process of converting ELCOM's systems to a larger network, thus providing economies of scale. An inventoryof all large hydro sites (over 50 MW) should be compiled and preliminaryfeasibility studies should be carried out on 3-4 sites selected from this list. Current work on a metallurgicalresource inventory should be continued in parallel.
3.15 The Government is to be commendedon its program for conser- vation of electricity,that is, the substitutionof solar for hot water heating. This is proving successful and is reducing ELCOM's peak and energy demand by a substantial amount (para. 3.40).
3.16 To supplement its current planning work, ELCOM should draw up a plan for least cost developmentof the power sector over a longer time frame of 15-20 years. In order to do this, however, studies on utilizationof on-shore/off-shoregas fields, the setting up of thermal stations at Port Moresby based on coal, and at Lae based on wood- wastes/coaland the feasibilityof large hydro sites, should be completed as a matter of priority.
Oil and Gas 1/
3.17 A significantamount of explorationwork has been performed in the oil and gas subsector over the past fifty years, particularlysince 1958 when the Petroleum Subsidy Act (PSA) was passed by the Commonwealth Government of Australia. Under the PSA, a subsidy of 50% was available for all approved projects, including geological and geophysicalsurveys and drilling of wells. All data collected under these approved projects, includingsamples and cores and copies of all documents had to be provided to the Government. Under this arrangement,28 wells were drilled, and 150 geophysicaland geological surveys were completed 2/. In addition 30 wells were drilled prior to 1954, though very little informationis available on these operations. About 30 wells were also drilled by private companies at their expense and partial data are availableon them. Nearly 40,000 kms of seismic work has been done to date, of which nearly 30,000 kms are in the offshore areas and 10,000 kms in the onshore areas. Most of the offshore data were collected during
1/ This report does not discuss the feasibilityof a refinery which was proposed in 1979 for PNG since the recent report on this feasibility (Oil Supply Options Study, RPT Economics Studies Group of London, January, 1981) showed that there was no justificationfor a refinery until domestic oil discoverieshad been proven. The mission concurs with this conclusion. 21 Robertson Research Consultantshave reviewed and catalogued all the work done up to date under the first phase of a World Bank aided project and its report has been recently circulated. - 32 -
1968-74 period. A complete set of this data is in the Government Archives at Canberra, and will become available to PNG on request. The second phase of the current petroleum exloration promotion project, which the Bank is financing,will be partly used to build up within the Geological Survey Division expertise in petroleummatters (generally referred to as Petroleum Resource Assessment Group or PRAG) and to provide for storage and documentationof all available materials in PNG.
3.18 There are three major basins in PNG; namely, (i) The Papuan Basin; (ii) The North New Guinea Basin; (iii) The Cape Vogel Basin and other minor basins in the smaller islands (Map 16281). The Papuan Basin is by far the largest (250,000 sq. kms) and contains most of the wells drilled. There have been six reported discoveriesthere: two offshore, namely Pasca and Uramu, and four onshore in the Gulf Province, namely Puri, Barikewa,lehi, Bwata 1/. Indicated gas reserves are estimated to be 1.5-5.0 trillion cubic feet (TCF); the wide range of estimates results from the fact that very little follow-up drilling has taken place around the discoveries. At Pasca, the confirmationwell had a gas flow at an estimated rate of 17 million CFD, with a significantquantity of condensates. The condensate reserve is estimated to be around 60 million barrels. However, the field is located in water depths of around 300 feet and may prove to be expensive to develop. Uramu gas field is in shallowerwater (30 feet) and therefore its exploitationmay be more economic. The discoverywell had a gas flow at 13-14 million CFD, and reserves are estimatedat 0.2-0.4 TCF. However, the gas is dry and condensate reserves would be minimal.
3.19 The onshore discoveriesare also prospective,the largest of which appears to be Barikewa, where the gas reserves have been estimated at 0.5-1.5 TCF. Drilling of the first delineationwell is in progress. Iehi appears to be the next best discovery,although no confirmation wells have been drilled. Bwata, and Puri are much more complex prospects and are likely to be smaller. The North New Guinea Basin covers about a third of the area of the Papuan Basin. Prospects here are less explored than in the Gulf area and no discovery has been made to date, although oil and gas shows have been noted both at the surface and in wells. Some explorationwork is in progress. In the Cape Vogel Basin and the smaller basins associated with the island margin very little work has been done to date. The gas discoveriesin the offshore and onshore areas of the Papuan Basin are not yet large enough to consider export potential, e.g. LNG; however, they should be adequate for the purpose of meeting domestic needs for power generation for a very long time 2/. In part, the present dilemma is that these discoveriesare not large enough for energy exports on 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 fully tested. 2/ One TCF could support gas productionrate in excess of 120 million cubic feet/day (MMCFD) - roughly the heating equivalentof 1 million tons per annum of fuel oil. - 33 -
exploit these resources solely for domestic consumption1/. But unless gas is used for power generation,dependence on imported oil is likely to increase over time. This is why a number of alternativesneed to be examined whereby gas for power generation and industry becomes available at Port Moresby and other areas and the export sector ensures the developmentof the gas fields and supply of gas for domestic consumption at reasonable costs.
3.20 The offshore gas fields, Uramu and Pasca, both located in the Gulf of Papua may be reviewed first. Two reports 2/, one on reserve estimatesand the other on gas utilization,both prepared in 1978, were made available to the mission. The resource estimateshave been made by the group holding the explorationlicense, which consists of Superior, Arco, and Sun. The gas utilization study was made by Pace Engineering on behalf of these companies and covered three possible scenarios: LNG alone, LNG and LPG recovery, and LPG recovery alone. The utilization study was based on the earlier reserve study and all three scenarios (as of 1978) resulted in unacceptableto very marginal economic returns.
3.21 A review of these reports suggests that (a) the recoverable reserve estimatesare conservative,and (b) the three scenariosused in the utilizationstudy do not cover all available options. The reserve estimatesare conservativewith respect to reservoirvolume, i.e. porosity of the reservoir rock and the gas/water contact, liquid production potentialat Pasca and recoverablefraction of in-place reserves. The earlier preliminary estimate of.l TCF and 60 + million barrels condensate recoverablemade by several workers for Pasca alone, based on data of Phillips Petroleum, may be more reasonable. Preliminary studies suggest that at current prices the field may well be economic. Given the gas/condensateratio of the reservoir, it may be possible to produce as much as 6,000 barrels per day of light product -- a quantity roughly equal to the current rate of consumptionof light distillates.If gas reserves of 1 TCF are confirmed, the Pasca field could support a gas production 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 methanol production.
3.22 There are many possible scenarios for conceptual design depending on the outcome of further drilling and testing. Some of them are:
(i) Liquids are stripped from the gas and the dry gas reinjected into the reservoir. The stripping could be
1/ Total volume of petroleum products used for electricitygeneration in 1980 is estimated at 247,000 TOE. 2/ "Reserve and DeliverabilityReport of the Pasca and Uramu Fields" and "The CommercialUtilisation of the North Delta Gas Resources in PNG - A Re-evaluation". - 34 -
done on the platform with liquids loaded directly to a tanker from a single buoy mooring system (SBM). The liquid products could either be entirely exported or used partly as a gasoline substituteor extender. The dry gas could be subsequentlyproduced for domestic use as and when required.
(ii) Both liquids and gas would be produced at once with some of the gas sold for domestic consumptionand the remainder reinjectedto maintain reservoir pressure. This case would require a pipeline to Port Moresby (either entirely offshore or partly offshore and then onshore).
(iii) In addition to alternative (ii) above, a shore-based methanol plant for domestic and export markets could be built.
These alternativescenarios, in addition to the three considered by Pace Engineering,i.e. LNG recovery alone, LNG and LPG recovery, and LPG recovery alone, are only indicative of the many different options available for developmentof the Pasca field and the consequentneed for an in-depth gas utilizationstudy which the mission recommends. If it proves possible to develop Pasca, the possibilityof developingthe nearby offshore Uramu field is enhanced.
3.23 The onshore gas discoveriesat Barikewa and Iehi also offer interestingpossibilities for development,the most importantbeing power generationwith gas turbines at or near the gas field and transmissionto Mt. Hagen or nearby, for connection to the Ramu grid. The onshore fields can be developedby themselveswithout reference to the offshore fields or to export possibilities. One productionwell may be adequate to meet the thermal power component of the Ramu grid and could possibly be completedquickly.
3.24 What emerges, therefore,is that there are many options which these offshore and onshore gas discoveriesprovide, and the mission recommends that these should be taken into account in drawing up any medium-to-long-termenergy plans. The mission recommends that the Governmentrequire speedier explorationand appraisal of discoveries by the oil companies as their work program comes up for periodic review under the terms of the licences already granted. Coal I/
3.25 Coal occurrenceshave been discovered in the Morobe and Gulf Provinces and near Madang (Map 16281 and Annex V). They have generally
1/ Material in this section is based on the GeologicalSurvey Report "Coal Occurrencesin Morobe and Gulf Provinces",,by R. Rogerson, April 1981. - 35 -
been small deposits of low grade coal with most seams dipping at moderate angles, mainly in rather remote areas, and it is expected that infras- tructure,extraction and transport costs for most of these reserves will be very high. However, several occurrences seem prospective, especially in Pindiu, Hohoro and Lower Purari:
(i) Pindiu area in the north: Blue Circle Southern Cement Ltd. has reported a 3 m seam with possible reserves of 40-50 million tonnes. The 1980 company report suggests the coal is sub-bituminousin rank. Reserve estimates have since been downgraded.
(ii) Lower Purari and Hohoro areas in the south: Large reserves made these ocurrences prospectiveexcept for the fact that the seams dip and the area can become flooded quickly making explorationand mining difficult and expensive. The characteristicsof the Lower Purari coal reserves are set out in Table 3.1 below.
Table 3.1
Lower Purari River Coal Characteristics
Variable Value Seam Thickness 0.4 - 2.63 m most > lm Moisture 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/kg Sulphur 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 informationavailable, it is generally agreed that technicallyrecoverable coal reserves exist in both Morobe and Gulf Provinces and that Pindiu, Purari and Hohoro areas seem most pros- pective. The economics of potential open-cut mines in these areas should be closely examined for the purpose of power generation in Lae and Port Moresby as an alternative to the use of Australian steam coal.L/ For this purpose priority should be given to geological explorationof the Pindiu area, and technicalassistance should be sought for this.
1/ The mission understandsthat there has been a moratorium on the issue of new mineral production licences because of personnel constraintsin the Division of Mines. - 36 -
Geothermal Resources
3.27 Manifestationof volcanic activity can be found in many-parts of PNG, and considerablegeological and geophysicalwork has been done to identify geothermal potential since 1950. A substantialpart of this work has been done on New Britain and D'EntrecasteauxIslands east of Papua, which are held to be the most prospective. There are surface evidences of hydrothermalactivity in the form of hot water seeps and geysers at temperaturesof 900-950C, particularlyin the Rabaul, Hoskins and Talasea thermal areas in New Britain and the Deidei and Iamalele thermal areas in the Fergusson Island of the D'Entrecasteauxgroup. There are no firm estimates of the potential of these areas, but a team from the Geological Survey of New Zealand carried out a preliminary assessment in 1974 and recommended that further geologicaland geophysicalwork be done 1Y. As the electricityconsumption in these areas (with the possible exceptionof Rabaul) is small and there is little or no consumptionof steam for process purposes, there is no urgency in developing the potential, but some priority may be given to identifyingthe potential of the Rabaul thermal area.
Renewables
3.28 The potentialfor energy from renewable sources is very large. A substantialpart of the land area is under forests, estimated at 40 million hectares. Only a small part of this resource is being used presently. In addition, agriculturalproducts and wastes could be used either directly as an energy source or in the form of biogas or ethanol. There is also a high rate of insolation spread over the year and applicationof solar energy for heat and electricitybecomes possible. However, wind and wave energy are likely to have negligible potential. Some of the more important renewablesare discussed in the following section.
Woodfuels
3.29 At present, about 1.0 million tonnes of woodfuel are being used per annum, 95% of which is consumed in the household sector for cooking purposes. The remaining5% is used in the industrial sector for drying and other low grade heat applications,particularly in agricultural processing. Expansion of wood utilization,especially in the industrial and power sectors, has been one of the objectives of energy planners. However, organized and systematicutilization is very difficult consideringthe lack of access roads into forest areas, the very high transport costs and possible adverse ecological effects. Yet the attraction of readily available wood residues, especially sawmill wastes which could easily supply industrial energy, led at first to emphasis on charcoal production. Charcoal was expected to become a standard industrialfuel since it is easier to transport than wood, it is storable
1/ "GeothermalInvestigations in Papua New Guinea" by G.W. Grindley and L.A. Nairn, August, 1974. 37 -
and can be used in existing equipmentwith a minimum of modification. Production of charcoal was to be carried out by use of batch operated kilns working on the larger waste pieces and by means of continuous pyrolysis systems processing the smaller-sizedmaterial, a method which also produces an oily fraction that can be used as industrial fuel. The various charcoal kilns used did not prove feasible and experimentation with others is still going on, while the pyrolysis project passed from a feasibilitystudy to the constructionof a small pilot plant at the University of Technologyat Lae. However, the plant was dismantled in November 1981 and moved to the Dylup cocoa/copraplantation near Madang.
3.30 With the demise of the industrialcharcoal program, focus was shifted to gasificationof wood wastes from the Lae Sawmills estimatedat 100,000 tons per annum. At present, there are no industrial scale gasifiers installed, though plans to put a gasifier/burnerin the Lae Brewery, in place of the existing oil-fired boiler, are being implemented. Wood gasificationfor running of stationary engines might have a greater applicationsince a number of diesel generating sets are operated all over the country. Many of these are in remote areas where it is difficultand costly to transport the diesel fuel, and woodfuel is available nearby. There is also the possibilityof using woodfuel for steam and power generation in conventionally-firedthermal power plants. This option has been examined for the Port Moresby area, and it has been concluded that the available woodfuel resources there cannot sustain a 10-15 MW power plant over the longer term. Such an option may be feasible in the Lae area where 100,000 tonnes of wood wastes are available, which are now disposed of by burning at considerablecost and pollution of surroundingareas. It is recommendedthat the possibility of using these wood wastes for steam/thermalpower generation be further examined.
3.31 In most of the rural areas, fuelwood is likely to continue to be used for cooking in the households, and the demand for this purpose may be expected to grow at the same rate as the population. In addition to its possible use as a substitute for diesel in the running of diesel generating sets in the remote areas and as a fuel for power generation, there is some evidence of increasing quantities of fuelwood being used in industry as a source of heat (e.g. for tea drying). These options should be further encouraged and woodfuel should be made readily available at reasonable cost especially to food processing and other non-mining industries.
Ethanol 1/
3.32 In its "White Paper" of 1979, the Government placed considerable emphasis on the developmentof ethanol production from biomass to substitute for transportfuel. A target of 130 m litres/annumproduction by 1990 was given and projects proposed for production of
1/ An internal report on ethanol projects in PNG is being prepared by the Industry Department of the World Bank. - 38 -
ethanol from cassava, sugarcane,molasses and sago palm starch. At the time of the mission a small (2.0 - 2.5 million litres/annum)cassava based project was under developmentin the Highlands at Baiyer River. Governmentstatements have emphasisedthe intention that ethanol productionshould be competitive in cost with fuel imports and further developmentof this project is contingenton its economic viability based on this criteria.
3.33 PNG experiencesa fuel deficit and enjoys an agricultural surplus. However, this surplus rests largely on tree crop products and there is no history of commercialproduction of sugar or cassava. On the other hand, in general there is a reasonablyabundant supply of cultivable land, and the availabilityof investmentfunds is a more important constraintthan land supply in spite of the complicated problems associatedwith land tenure in PNG. At present, a national sugar industry is being created in the Ramu Valley, with an initial target output of 30,000 tonnes/annum. Molasses by-productfrom this industry is expected to be the single most promising feedstock for ethanol production,in view of its low opportunitycost. At Baiyer River, local cassava varieties planted for the ethanol project are giving extemely impressiveinitial yields (70 tonnes/hectare). Naturally- occurring stands of starch-bearingsago palm (and of the nipa palm which yields a sucrose - rich sap) are extensive,but collectionsystems are likely to prove problematic.
3.34 The economic and financial viabilityof ethanol productionin PNG will be far more location-specificthan in most countries,because of the unusual lack of geographicintegration. As Map PNG 16180 illustrates,the national road system and hence the market for motor spirit comprisesa series of coastal towns or cities, each with its own hinterlandroad system, but only connected to each other by sea or air. The larger coastal towns land refined petroleum products directly from internationalvessels (Port Moresby, Lae, Rabaul, Madang, and Arawa Bay for Kieta), while smaller ports must rely on domestic coastal transshipment(e.g., Wewak). The consequenceof this fragmentationof an already small national market for gasoline is to add significantlyto the barriers facing any potentialethanol project, since productionwhich exceeds the absorptivecapacity of a small immediatemarket would have to bear the additionalcost of coastal shipping to another region of the country.
3.35 As a result of these locationalfactors, the ethanol plants under considerationare mostly very small by world standards and unable to benefit from economies of scale. In addition, PNG's topography, poorly developed infrastructureand shortage of indigenous technicaland managerial skills greatly increase costs of construction and operation of ethanol plants compared to countries like Brazil. The Baiyer River ethanol plant (capacity8-10,000 litres/day)will cost about five times as much per unit of daily capacity as an optimal scale plant in a 'low cost' country. This particularproject, unlike the others being considered,would benefit from 'natural protection'since gasoline imported to the Highlands must bear heavy transport costs. However, even - 39 -
allowing for this factor and writing off over US$2.0 m already spent, the economic viability of project continuationwould appear marginal at best.
3.36 Apart from production-sidedifficulties posed by high plant capital costs and technicaluncertainties relating, for example, to the proposed sago palm components,the government'soriginally published ethanol targets have been recognizedas over-ambitious. Quite apart from the technical problems, substitutionof ethanol for gasoline in the transport sector could not absorb more than 30% of the originally proposed 1990 production (unless heavy subsidies were introduced) 1/, and technical problems to substitutionfor diesel are severe. The government has recognisedthe problems involved in the original plans and is continuingto cut back the ethanol program radically.
3.37 Proposalshave been prepared to add an ethanol plant to the sugar mill under constructionin the Ramu Valley. Such a plant would enjoy a number of advantagesunique within PNG. Capital costs for the ethanol project would be significantlyreduced, especiallyon the 'front end', through sharing of facilitieswith the sugar mill. Much of the feedstock for the alcohol plant would be by-productmolasses, whose alternative export value after deducting transport costs would be very low. Finally, the project is well placed to serve the sizeable market in the industrial city of Lae and at least the lower stretches of the Highland Highway, enabling the plant to be built to an intermediate capacity of 30,000 litres/day(i.e. annual output 6.0 m liters which is about 5% of annual gasoline consumptionin 1980 estimated at 117 million litres). A consultant'sfeasibility study for this project estimatesan economic rate of return of 18%2/. If this is so, then the Ramu Valley ethanol proposals must be considered economicallyattractive. Other projects, however, are unlikely to prove economicallyviable unless world gasoline prices record further significant increasesor considerable progress is made in reducing capital costs of small-scaleethanol plants. Any proposed new ethanol projects must prove their economic viability before further investment in them is made. Biogas
3.38 Early in its lifetime the EPU facilitatedcontracts between AppropriateTechnology International(ATI) and the Lae City Council to build a biogas plant operating on night soil and severage, and later it arranged a deal between the PNG Coffee Board and a Waghi Mek (near Mt. Hagen) coffee cooperativeto build a small scale demonstrationbiogas plant operating on the pulp from coffee cherries. The program has had mixed success, with the coffee project being by far the more promising of the two. However, visits to the sites have revealed that both plants are currently inoperativefor technical reasons. Although biogas is not seen as a major industrialenergy source on a national scale, it does offer a means of producing energy at some sites, especiallyin remote areas, but
1/ Detailed analysis available in Bank internal report on PNG's ethanol projects, referred to in footnote page 37. 2/ Recent communicationof EPU. - 40 -
this would necessitatefurther improvementin the digester design by the manufacturer. However, the mission believes that no additional effort by the EPU is required to facilitate introductionof this technologywhich has only limited applicationin PNG for the present.
Mini and Micro-Hydro
3.39 While agreeing that micro-hydro is in principle ideal for small villages and rural electrification(RE), EPU notes that in the 5 kw size or so, the unit cost is K 3,000-4,000per installedkw, the unit is subject to fluctuatingwater availabilityand silt damage to headworks and turbines and, for firm load, must be supported by diesel which amortized 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-hydro stations financed by the Asian DevelopmentBank, (i) Tinputz (200 kw, K 532,000, cost/kw K 2600, cost of energy 16 toeas/kWh) and (ii) Lake Hargy (750 kw, K 1,900,000,cost of energy 16 toeas/kWh). In fact the constructionof these two projects was suspended in April 1981 in view of the large cost overruns experiencedby the Sohun (commissioned1980) and Ru Creek (commissioningApril 1982) mini-hydros,and the indication that Tinputz and Lake Hargy were going to incur large overruns, possibly up to 100% of original cost estimates. One of the main advantages of micro- hydro in countries other than PNG is that a substantial,if not all, part of the inputs including rotating machinery can be procured and maintained locally. However, no local materials or adequate expertise exists in PNG, and thereforesuch plants may not be as viable in PNG as in other countries. (For further discussion of rural electrificationsee Annex T I). Solar Water-Heating
3.40 The Government has underway a highly successfulprogram of conversion from electric to solar hot water heating. A typical installation,imported from Australia to install or retrofit an existing electric hot water installationcosts about K 700 for a 70 gallon tank. With the current high tariffs, it is expected that it would pay for itself in 2-3 years. In areas where there is a substantialrainy season, back-up electricitywater heating is necessary. It is understood that solar heating equipmentmight be manufacturedin PNG within a year.
3.41 EPU expects that sometime in 1982/83 some 7000 hot water solar heating units will have been installed. The high rate of installation reflects a response to Government regulationswhich effectivelybanned installationof electric hot water heaters in new homes and buildings and provided tax write-off incentives to retrofit existing electric installations. The 7,000 solar installationswill result in a substantial reduction of the electricity peak and energy demand, perhaps as much as 7MW out of total (ELCOM) installed capacity of 167 MW depending on the coincidence 1/ factor applicable to all electric water
1/ The coincidencefactor is the fraction of all electric water heaters in the system that would be switched on simultaneouslyat any one time. - 41 -
heaters in the system and realizing that most locations would require boosters for the rainy season.
Photo-VoltaicCells (PVC)
3.42 PVC can be used to provide light or refrigerationor to run water pumps and fans. At the high cost of K 550 (US$825) for a two light installationin villages isolated from the power network, it is uneconomical. Aside from cost, there is also the equipment reliability problem. PVC is, therefore,more likely to be used for the power supply of telecommunicationequipment or refrigerationof medical supplies in isolated areas. Its broader use for rural electrificationis unlikely to develop not only because of cost, but also because in most rural householdseven the use of kerosene for lighting is negligible (estimated at about 22 litres per household per annum). However, as the cost of cells declines in the future with improved technology,these and other applicationsmay become more attractive. For this reason the relatively low level of funding on these projects may continue.
Wind-ElectricGeneration
3.43 Wind in PNG is comparativelylocalized. Moreover, wind generationis fairly complex, and, coupled with the isolation of such installation,would be difficult and very expensive to maintain. It does not appear likely therefore to be a factor in the rural electrification program. - 42 -
CHAPTER IV
ENERGY OUTLOOK TO 1990
Introduction
4.01 Papua New Guinea has a wealth of natural resources to be exploited,and many of them lend themselves to large enclave developments which, like BCL in the early 1970's, and Ok Tedi in the 1980's, would eventuallymake a substantialimpact on the economy and especially on energy supply and demand. On the supply side the main energy exporting option would be one based on the already discoveredgas fields. Whether this would take the form of direct LNG exports, or whether it would require the processing of gas into methanol or ammonia/urea,will depend on the size of the field, the market prospects of the alternatives,and the capital requirementsfor such industries located in PNG. Another option that is being considered is the developmentof a large hydro based aluminum smelter (althoughthis is unlikely to materialize during the 1980's), which would allow the indirect export of the hydro electricity embodied in the aluminum 1/. This might have the additional advantage of providing a surplus of cheap electric power for domestic use, displacing fuel imports. At the moment, all electricityoptions available are handicappedby small scale and consequent high costs, but the development of large enclave hydro-basedindustries would break this constraint,at the same time solving many of the problems of supply reliability.
4.02 The view taken in this forecast is that the aluminum smelter is unlikely to materializein eight years, partly because market prospects for aluminum look poor in the near future, while the hydro scheme necessary for a metallurgicalindustry would have a substantiallead time. No new enclave minerals projects are included in the forecast, and so the structureof the economy is assumed essentiallyunchanged on the demand side.
Electricity
4.03 Forty percent of all petroleum imports are used for power generation,for which there are many substitutionoptions available. Table 4.1 summarizes the forecasts for electricitygeneration by BCL, Ok Tedi, the public utility network (ELCOM) and small captive generation.
1/ Several aluminum companies, includingAmerican and Japanese companies,have shown interest in utilizing these resources. - 43 -
Table 4.1
Forecast of ElectricityGeneration, 1985 and 1990 (GWh)
Rate of Growth 1980 1985 1990 1980-85 1985-90 (%) (%)
BCL 790 1185 1440 8.4 4.0 Ok Tedi - 87 225 - 24.0 Elcom 412 857 788 6.2 7.2 Others 51 35 49 -7.3 7.0 Total 1253 1864 2532 8.3 6.3
4.04 A number of options are available for generatingelectricity: hydro, indigenousgas, imported oil, and imported coal. Given the Ienclave type of developmenttypical of PNG, the three major generating entities namely, BCL, Ok Tedi and ELCOM may adopt many different strategies,depending on the extent of government intervention,the results of feasibilitystudies yet to be carried out, and the speed with which gas resources are developed. Based on certain assumptions regarding use of coal and gas, three supply scenarioshave been worked out for 1990. For 1985, there are no alternative scenariosdue to the short lead time availablealthough by then BCL may switch to coal-fired thermal plant. The likely option now 1/ is to install 2x45 MW coal-fired steam generators. The three scenarios envisaged by the mission to supply electricityin 1990 are summarized below:
1. Case A (Gas Case): This is the optimistic case which assumes that Pasca gas field will be developed, that gas will be piped to Port Moresby for power generation and the condensatesfrom Pasca will be recoveredand exported. Hydro will be developed at BCL, in addition to the coal- fired thermal station mentioned above. Investment costs in this case, exclusive of a methanol plant, are estimated at about US$850 million (Table 6.1). A variant to the above scenario providing for methanol production for export has also been considered.
2. Case B (Coal Case): This case assumes that coal will be used for power generation at Port Moresby and BCL would add more coal-fired plants, all at a total cost of US$555 million.
1/ As recommendedby consultantsto BCL (para. 2.13). - 44 -
3. Case C (Businessas Usual) (BAU): Dependence on fuel oil and distillatesfor a substantialpart of thermal.generation continues,and a run-of-riverhydro for ELCOM. Investment in this case would be smallest,at US$430 million.
In all the three cases, Barikewa gas is used for power generation for the Ramu grid.
4.05 The break-up of electricitygeneration by hydro and by thermal fuels for 1985 and for the three supply options for 1990 is given in Table 4.2:
Table 4.2
Break-Up of ElectricityGeneration in 1985 and 1990 (GWh)
1985 1990 Case A Case B Case C
Gas Coal BAU
Hydro 345 990 640 790
Thermal
Diesel 495 252 252 272 Fuel Oil 1045 - - 1320 Gas - 300 130 130 Coal - 900 1510 - Total 184 2532 2325 232
4.06 The correspondingfuel inputs required for the different scenariosis shown in Table 4.3. - 45 -
Table 4.3
Fuel Inputs Required For ElectricityGeneration ( 000 TOE)
1985 1990 A 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 that consumptionof fuel in transport is expected to grow at an annual rate of only 2% reflecting the effects of a switch to smaller more fuel efficient vehicles and possible reduction in the number of expatriatesworking in the country. In the second half of the decade gasoline consumption is forecast to grow at 3% per annum and distillatesat 5% per annum. These rates are slightlyhigher than those achieved in the past decade, but in that decade real prices rose 100% and GNP stagnated. In the 1980's further substantialreal price rises are less likely, and GNP is forecast to grow more rapidly. Moreover, demand for shipping by Ok Tedi is projected to build up to 112,000 tonnes per annum by 1990. Air transport is also assumed to grow, and Avtur consumptionis 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 per annum to offset the decline in ore quality, and possibly increase concentrate production. This will increase demand for distillate fuel and implies a 1990 consumptionof distillates of 51,100 tonnes. Ok Tedi will have reached Stage III by 1990 and is assumed to consume 21,200 tonnes of distillatein mining and processing ore, and 7,000 tones of fuel oil in copper concentratedrying. Agriculturalprocessing is assumed to continue substitutingbiomass for oil, thus reducing its - 46 -
demand for distillatesto 4,000 tonnes while biomass demand rises by 3% per annum to 88,000 TOE. Remaining industrial fuel use is assumed to grow at 7% but its compositiondepends on the relative prices of alternativefuels. If gas and condensatesare available in Port Moresby there will be some substitutionof gas for other fuels.
Other Sectors (Agriculture,Households, etc.)
4.09 Tractor demand for distillate is assumed to rise at 3% per annum reaching 5,200 tonnes by 1990 for the agriculturalsector. Kerosene consumptionin the household sector is assumed to grow at 5% per annum to 28,000 tonnes by 1990. Urbanizationis expected to continue at past rates. Per capita woodfuel consumptionis assumed to remain constant in both 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 calculationshave been made to show the effect of methanol production on the import bill (Table 4.7). Annex I, Table I.9 correspondsto the coal option while Annex I, Table I.10 reflects the Business-as-Usualscenario. Table 4.4 below shows forecast final energy consumptionpattern for 1985 and 1990 1/.
1/ Annex I, Table 1.11 shows final energy consumptionwithout copper (BCL and Ok Tedi) and exports. - 47 -
Table 4.4
Forecast Final Energy ConsumptionPattern for 1985 and 1990 (in -000 TOE)
Electricity Petroleum Woodfuel Total
1985
Households 12 22 430 464 Industry 126 93 - 219 Transport - 297 - 297 Others (Agr. and Commerce) 15 8 70 93 Total 153 4201/ 500 1073
1990
Households 17 28 473 518 Industry 172 122 - 294 Transport 20 367 - 367 Others (Agr. and Commerce) 20 9 88 117 Total 209 526_/ 561 1296
Growth Rates (%) 3/
1980-85 8.5 2.5 2.9 3.4 1985-90 6.4 4.6 2.3 3.9 1980-90 7.4 3.6 2.6 3.6
1/ Does not include 392,000 TOE used for power generation already included in electricity. 2/ Does not include 475,000 TOE used for power generationalready included in electricity. 3/ Historical growth rates in total energy consumptionduring the seventies are as follows: 1970-75 9.3% (BCL started operation in 1973) 1975-80 3.6% 1970-80 6.4%
4.11 Three condensedenergy balances appear in Annexes I (Tables I.7, I.9 and I.10) correspondingto the three scenarios outlined in para. 4.04 and 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 43 Hydro 304 197 243
Plus Imports
Coal 304 447 Petroleum 573 598 988
Less Exports
Condensates -178 -
Total CommercialEnergy Required 1305 1285 1274
Less Transformation Losses (generation and other losses) -570 -550 -539
Total Final Commercial Energy 735 735 735
Non-CommercialEnergy 561 561 561
Total Final Energy 1296 1296 1296
1/ Annex I (Table I.8) also shows Case A (Gas) in detail with the productionand export of methanol. 4.12 Energy inputs will be higher than the final energy consumption shown in Table 4.4 by the transformationand transmissionlosses in the electricity sector and by exports. The gross energy inputs are shown in Table 4.6 below. - .49,-
Table 4.6
Forecast Gross Energy Inputs for 1985 and 1990 ('000 TOE)
1985 1990 A B C (Gas) (Coal) (BAU)
Final energy consumption 1073 1296 1296 1296 Transformationlosses 345 570 550 539 Exports (condensates) - 178 - - Total Gross Energy Inputs 1418 2044 1/ 1851 1835
1/ If exports of methanol are included in this case, transformation losses would increase to 752,000 TOE, exports to 492,000 TOE, and total inputs to 2,540,000 TOE.
4.13 The net imports ot fuels and their cost shown in Table 4.7 below:
Table 4.7
Forecast Net Fuel Imports 1985 and 1990
1980 1985 1990 A B C (Gas) (Coal) (BAU)
Imports of fuels in TOE (Table 4.5) 619 812 877 1045 988 Cost of fuel imports (million 1980 US$) 188 287 290 319 381 Less 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 vicinity of 660,000 tonnes valued at US$ 137 million. - 50 -
4.14 Although larger quantities are imported in Case B than in Case C, the import bill is lower because cheaper coal substitutesfor more expensive 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 for an export-orientedpetrochemical industry such as methanol. Rough calculationssuggest that a 2000 tons per day plant may cost around US$300 million and increase energy exports by US$137 million per annum and 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-$381million, or from 13%-22% of export revenue (Table 4.7). Thus, if PNG does not exploit any exportable energy resources, imports of oil will continue to cost their currentlyhigh share of export revenue (24% in 1980) eroding the increased revenues from mining. In Case A (Gas) with exports of condensatesand methanol, the deficit on energy trade falls to $82 million (assumingmethanol exports equivalent to US$137 million) or 5% of projected export earnings which is below its share in 1969-70.
4.16 These scenarioshave been done only for the purpose of illustratingthe options available in the energy sector and the order of magnitude of energy imports and their costs. Detailed studies will be required to estimate the profitabilityor otherwise of the different componentsof these three scenarios, or other scenarios.
I/ GNP is assumed to grow at the rate of 4% per annum during the eighties, perhaps higher in the first half as Ok Tedi starts production. - 51 -
CHAPTER V
INSTITUTIONSAND POLICY PLANNING
Introduction
5.01 The Department of Minerals and Energy (DME) is the organization which oversees most activities in the energy sector. The Geological Survey Division within DME is responsiblefor technical advice on all explorationmatters concerning the oil and gas sector, the coal sector and geothermal sector, in addition to similar activities in the mining sector. The other major divisions of DME are the Bureau of Water Resources which is responsible for the collection of all hydrological data relating to streams and rivers and evaluation of potential hydroelectricsites, the National Weather Service and the Division of Mines, which is responsible for the implementationof the Petroleum Act, issuing of licences, monitoring of safety and the organizationof the Petroleum Advisory Board (PAB). These four divisions are under the overall supervisionof the Policy and Planning Division, which has responsibilityfor coordinationof negotiationsover oil and gas concessionsand formulationof policy with respect to exploration activities. The power sector is run by the Electricity Commission (ELCOM) whose chairman reports to the Minister of DME. The organizationalchart of the DME as of November 1981 is shown in Annex VI.
5.02 In addition, a forum for interactionand exchange of information among the various parts of government on developmentsin the energy sector is provided by the National Energy Planning Council (NEPC). This was designed to be an interdepartmentalgroup, with no executive powers, headed by the Minister of DME and representativesof the following: Department of Primary Industry, Office of Forests, National Planning Office, Department of Finance, ELCOM, Department of Works and Supply, Office of Village Developmentand Office of Environmentand- Conservation. The Energy Planning Unit (EPU), which also reports to the Policy and Planning Division, acts as the Secretariatfor NEPC.
The Geological Survey Division
5.03 At present, the Geological Survey Division within the Department of Minerals and Energy, headed by the Chief Government Geologist, is in charge of explorationfor minerals and petroleum. With regard to the latter, it is responsible for the collection and review of past explorationdata from oil companiesand for advising the Petroleum Advisory Board on technical matters. The actual monitoring of contracts falls under the Division of Mines of the same Department. From a brief review of the Division's staff, it becomes readily clear that PNG lacks expertise in petroleum matters such as petroleum engineering. About six expatriatesand six PNG nationals, all explorationgeologists and geophysicists,look after both minerals and petroleum. Because of the importance of oil and gas for PNG, and consideringthe need for early utilization of already firmed-up gas reserves and the possibilityof - 52 -
finding oil, it is recommeded that the existing group in the Geological Survey Division be strengthenedby hiring highly specializedpetroleum experts 1/. At a later stage considerationmay be given to the establishmentof a separate oil and gas agency. Such an agency, when formed, would include specialists in all areas of petroleum exploration and production. The new agency would be responsible for all aspects of the oil and gas sector including negotiationof contracts with oil companies as well as monitoring of contracts,duties now shared by the GeologicalSurvey and the Division of Mines.
5.04 The GeologicalSurvey Division also handles geothermal explorationand has a volcanologicalobservatory, based in Rabaul which maintains seismic and geomagneticmonitoring stations throughoutPNG. Only limited work has been done by the GeologicalSurvey Division to establish the geothermalpotential. The same also applies to the coal sector. Although there have been reports of occurrences of coal and lignite, especiallyin the Gulf Province, in the Central Highlands and New Britain and New Ireland, the DME has not promoted adequate exploratorywork to establish reserves. This again might be an indicationof the many varied responsibilitiesof the Geological Survey Division and the need for strengtheningit in the area of coal exploration.
The Energy Planning Unit
5.05 The Energy Planning Unit was establishedat the end of 1978 within the Department of Minerals and Energy for the purpose of formulatingenergy planning and policies. Its staff has increasedfrom 2 at the end of 1980 to eleven professionals,mainly expatriates,with its main expertise in the renewable forms of energy. The Governmentissued in 1979 a "White Paper" prepared by EPU setting out PNG's energy plans and policies. The "White Paper" put the main emphasis on the production of energy from renewable sources, and proposed many projects, some of them without adequate technicalor economic appraisal. EPU did not confine itself to energy planning,but also became involved in promoting energy projects based on renewables. Some of these projects, particularlythose dealing with ethanol, seem to have been initiated without adequate data, and a cost reappraisalof these projects has already led to some of them being abandoned. The availabilityof a tremendousbiomass resource makes it a natural target for development in an energy hungry country like PNG. However, inappropriatetechnologies seem to have been chosen for some of the utilizationof biomass with the result that substitutionof oil by biomass in industry, other than agriculturalprocessing, has not taken place to any significantextent.
5.06 In view of the importanceof energy planning in PNG, with its
1/ This is now being contemplatedas a component of the second phase of the petroleum explorationproject being financed by the Bank. - 53 -
varied energy resources, it is recommended that the role of EPU be redefined as follows:
(i) EPU should function as an overall energy study and planning agency, whose function will be to prepare integrated energy plans, and not focus mainly on renewable energy planning. Such integrated plans would be based on demand and supply forecasts prepared by the respective agencies for power, coal, oil and gas and woodfuel and the user sectors and sub-sectors. This would require close coordination with, among others, ELCOM, the Geological Survey, and the Forestry Office of Department of Primary Industries (DPI). The expertise of EPU's staff should be diversified so that it can handle its new responsibilities as well as effectively monitor energy policies, programs and conservation measures.
(ii) In order to emphasize the importance of overall energy planning, the promotion and implementation of renewable energy projects and conservation measures could be entrusted to a separate unit under the Division of Policy and Planning.
ELCOM
5.07 ELCOMis a statutory authority, responsible for all aspects of Government's public electricity supply system 1/. It was established under the Papua New Guinea Electricity Act of 1961 under the Australian administration and continued in this form after independence in 1975, under the authority of the Minister of Public Utilities and a Government appointed Board of Commissioners. In 1978, it was placed under the Minister of Minerals and Energy. This transfer took place at about the same time as the establishment of the National Energy Planning Council (NEPC), which had a mandate to review and develop forms of renewable energy (other than hydro) on an integrated basis. ELCOM's fortunes and authority have, in a sense, declined in the period 1978-1981, while those of EPU, which was established in 1978 and was designed to act as Secretariat to the NEPC, have been in the ascendency. As a consequence, EPU eventually took over de facto responsibility for ELCOM's major planning, generation, and transmission facilities in the context of its national responsibility.
5.08 In March 1981 the Electricity Commission (Amendment) Act, 1981 amending the Electricity Commission Act, 1961 - was passed whereby (i) the composition of Commission Membership was changed: the six members to include the Secretaries of Finance, Minerals and Energy, and Lands and the Director of the National Planning Office, and two persons appointed to 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 was concurrently appointed interim General Manager of ELCOM, becoming head of both organizations. The period of appointment terminated early in 1982, when the incumbent left both EPU and ELCOM.
5.09 ELCOMhas operated with three departments (commercial, management, engineering) and several divisions and sub-divisions (electrical, generation, transmission/distribution, finance, administration, supplies and more recently, provincial electrification). Within this framework there have been considerable shifts in organizational and personnel emphasis, e.g. expatriates vs nationals in positions, numbers and depth of responsibility. Thus, the number of expatriates decreased substantially in 1974-6, remained steady until 1979 and increased sharply in 1980. This latter trend reflected a decision by ELCOMto do more in-house 1/ (in particular, its own design and construction), and about 30 expatriates were hired for the purpose.
5.10 In-house design and construction was certainly inadvisable for a utility of the moderate size but considerable complexity of ELCOM. In the Commissioner's Policy Paper of July 1981 to the National Executive Countil, ELCOMreversed its stand and in future, design and construction will be done by consultants and the private sector. Among other deficiencies focused on by management consultants and the "new" management (EPU-ELCOMcommon chief) were: the approach to nationalization of staff, training, planning, management reporting cum decision making, tariff structure, financial control of projects, salary levels and recruitment.
5.11 Planning capacity at ELCOM, has not been adequate. The Systems Planning Division was not given authority to select and analyze a range of generation options, being told which option to analyze by Design and Contracts. The most common criticism is that ELCOM, traditionally managed by expatriates till independence, deteriorated considerably when inadequately trained nationals took over much of management. However, even with the shift back to expatriates and EPU's intervention in the last 2-3 years, the decline in planning has continued, although some problems faced have at least been checked. Furthermore, some of the more intractable problems had their genesis in the pre-independence era; for example, the Ramu hydro concept and design.
5.12 The new management appointed to run ELCOMfrom early 1982, comprises a general manager, who has been appointed for five years, and a team of four specialists from Montreal Engineering. Senior nationals in responsible positions are to work with the team over a three-year period in order to obtain experience so that they can ultimately replace them. These nationals will also be given training in their fields in foreign countries. The result of these changes will depend much on the quality of the new general manager and the Montreal Engineering team. If between
1/ The Pauanda hydro plant was designed by ELCOMstaff. - 55 -
them they have extensive experience in moderate sized utility administrationand the capability to do power systems planning as distinct from design and engineering,success is likely, more so if they can change the episodic manner in which planning has been and is being done.
Bureau of Water Resources
5.13 The Bureau of Water Resources (BWR) is responsiblefor the collection of all hydrologicaldata relating to streams and rivers, and evaluation of potential hydroelectricsites. The interactionbetween BWR and ELCOM in the past has been inadequate and could have resulted in sub- obtimal planning of hydroelectricgeneration. As the major energy resource of PNG is its vast hydroelectricpotential, the misison has recommended: (a) an inventory of all large (50 MW plus) hydro sites, so that preliminary feasibilitystudies can be made for 3-4 of these sites for potential developmentof metallurgical enclaves;
(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 interactionbetween BWR and ELCOM be strengthenedin the selection and planning of all future hydropower stations,with BWR identifying potential hydropower sites and ELCOM determiningthe potential capacity and the necessary investment decisions. - 56 -
CHAPTER VI
ENERGY SECTOR INVESTMENT
6.01 Over the past seven years, public investment in the energy sector has been confined to the power sector. Annex II shows ELCOM's investment program over these years which seems to have declined in real terms over the past three years.
6.02 During the same period, there has been private investment in the energy sector by BCL for the 3x45 MW sets being used for captive generation. There has also been some additional investment by industry and commerce for power generation in small diesel generating sets. A much larger volume of private investment,(except for the subsidy under the Petroleum Subsidy Act during 1954-68) has gone into oil and gas exploration.
6.03 Possible investment outlays in the energy sector (excluding petroleum explorationand coal prospecting)under the three scenarios outlined in para.4.04up to 1990 have been very roughly quantified by the mission and are shown below in Table 6.1. Petroleum exploration activities have recently picked up and current exploration expenditures may reach a figure of US$30-40 million per annum, all of it by the private sector. It is rather difficult to predict future investment in the oil and gas sector as it would depend on the number and size of new discoveriesand these investmentsare thereforenot included in 6.1. A very preliminarycost estimate of US$240 million for Pasca field developmentwith recovery of condensates and gas pipeline to Port Moresby is, however, included.
6.04 Besides the development of the gas fields, the other major investmentwould be in the electricity sector, by ELCOM, BCL and Ok Tedi. Investment cost per unit of capacity installed,especially for hydro, varies widely with the type of plant, scale and location. Various figures have been derived from different sources and are used for the investment figures in Table 6.1. Ok Tedi energy investments(including 6x3.6MW diesel sets and the 46MW hydro plant at Ok Menga) are roughly estimated to cost US$168 million. BCL investment in the energy sector depends on the option from available choices--useof imported oil or imported coal or hydro or a combination of these. The most economic in terms of capital costs (in contrast to operating costs) would be to continue with oil, and the most expensive would be to switch to coal for thermal generation and developmentof new hydro with a storage dam. Investment figures for BCL therefore vary from US$50 million to US$280 million. ELCOM investmentsare estimated at US$157 million to US$210 million over the next 8 years. Table 6.1 gives an idea of investment forecasts for the energy sector up to 1990. These figures are largely illustrative,given the considerabledifferences between the various scenariosand the lack of reliable cost estimates. - 57 -
Table 6.1
Investmentin the Energy Sector 1981-1990 1/ (Million US Dollars)
Case A Case B Case C (Gas) (Coal) (BAU)
ELCOM
Investment to 1985 2/ 140.0 140.0 140.0 Other investment 15.0 15.0 15.0 Port Moresby electricity 12.0 43.5 67.5
Gas Field development 150.0 - - Gas Pipelines to 'Port Moresby 90.0 - -
BCL - hydro 150.0 - - BCL - coal 132.0 200.0 49.4
Ok Tedi diesel 18.0 18.0 18.0 Ok Tedi hydro 150.0 150.0 150.0
Total 4/ 857.0 3/ 565.0 440.0
1/ The estimates for hydro investmentsare based on figures from CT Main for a variety of hydro projects,most of which have capital costs (in US$ 1980) in the range $1500-2500/kwcapacity for run-of-river. Diesel costs are assumed to be $800/kw, coal between $1350-1500/kwdepending on scale, and oil fired thermal $1000-1125/kw. The coal and oil figures are taken from 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 investmentin a methanol plant estimated at $300 million. 4/ Does not include investmentin coal prospecting,which may amount to about US$3 million over the decade.
6.05 Table 6.1 sheds light on possible energy sector investment depending on the supply side scenarios discussed in Chapter IV. With the exclusion of exploration expenditureof oil and gas ($30-$40m per annum) and investmentin a gas based export oriented petrochemicalplant at Port Moresby under Case A (about $270 - $300 m), investment can vary from US$430 million for Case C, US$555 million for Case B and US$847 million for Case A. Although Case A (Gas) appears high, Table 4.7 showed that it could reduce the import bill by $162 million per annum compared with - 58 -
Case C(BAU). These comparisonsignore other costs, but help place the investment levels in perspective. The cost/benefitratios of these various 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 ForecastingMethodology
1970, 1975, 1979 and 1980 Balances (Tables I.1 - I.5)
1. The first step was to construct energy balance for "1970", "1975" (actuallyaverages of fiscal years 1969/70 and 1970/71, 1974/75 and 1975/76) 1979 and 1980 (since there was evidence to believe that 1980 was a somewhat atypical year). These balances were based largely on import data for liquid fuels, data from ELCOM for electricityproduction and use, and EPU data in woodfuel consumption. Industrialfuel use was based on Newcombe'ssurvey of fuel use in Lae and evidence collected by EPU, and discussed in paragraphs 2.11 - 2.20 of the text. The energy balance for 1980 is also shown in original units in Table 1.4 (to show the link to the historicaldata).
Energy Balance 1985 (Table 1.6)
2. Forecasts for fuel consumptionfor 1985 and 1990 were then based on estimates of sectoral growth rates, fuel substitutionpossibilities, and likely developmentsin each sector as set out in Chapter 4. For example, BCL's projectionof power demand, and Ok Tedi's developmentplan were used to project fuel demands by the mining enclave, while the gradual substitutionof biomass for oil in the agriculturalprocessing industries,described in para. 2.16, allowed oil demands in non-mining industry to be projected.
3. The 1985 forecasts could be checked against two other forecasts made 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 Mobil LPG 5 4 - 6 4.5 Avgas 7 5 - 9 9 6.5 Mogas 98 90 - 110 103 91.4 Avtur 50 47 - 68 66 57.0 Kerosene 22 17 - 26 26 17.0 Distillate: Agriculture 5 Transport 133 Mining 49 Other Indus. 28 Electricity 126 Total 341 231 - 415 344 328 Fuel Oil 285 137 - 305 280 249 Coal 0 0 - 218 Total 808 653 - 964 73W - 60 - ANNEX I Page 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 scenarios have been constructed to illustrate the range of possible options open to the economy.
5. Finally, the underlying developmentof the economy can be better appreciatedby excluding the enclave mining and gas-based export sector. Table I. 11 below is directly comparable to Table 2.2 of the text. ANNEX I Page 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 IEA Total 7 8 9 Motor Petroleum Row Total Non- Total Gaso- Kero- Distil- Residual Products Elec- c/ Cols Commer- Cols No, ____ _ LPG Avgas line Avtur sene late Fuel Oil. Incl _.PG _ Hdro tricity- cial 9-10 IIndig.Prod 41 41 343 384 2 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 Sector Use & Loss -1 -1 -la,
Total Final. 14 ConstumptioLn 2 17 58 31 9 81 12 210 15 225 343 S68
Miiiing 18 Otlher 1 13 12 26 10, 36 26 62 19 Transport 20 Road 58 54 112 112 :'2 Air 112 17 31 48 23 Coastal 48 48 11 ll 11 24 ot:her Sectors 11 25 Agc. 3 3 3 3 25 Commerce 1 1 27 I;ub.Service 1 2 2 28 Domestic 1 1 1 Rulral 4 4 Urbari s 4 307 311 5 3 8 10 18
Note /a Onecietric ton of oil equivalent is defined as 10 million K call lb 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 9 IEA liotor Petroleum . Total Non- Total Row Gaso- Kero- Distil- Residual Prodtucts Elec-/ Cols Commer- Cob No0. IPG _Avgas l ne Avtur sene __ ge Fuel Oil . LP !ydZ. tricitv 3-8 _al 9-10
1. Indig.Prod 64 64 389 453 2 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 I Use & Loss -3 -3 -3-
'rotal Final 14 Consumption 3 13 87 30 14 137 7 291 0 84 375 389 _ 764 15 Industry
Mininlg 21 21 58 79 79 18 Othier 2 27 7 36 ],3 49 38 87 19 Transport
20 Road 87 72 159 159 159 22 Air 13 30 43 43 43 23 Coastal 14 14 14 14 24 Other Sectors
25 Agr. 3 3 33 26 Commnerce 1 1 2 4 6 6 27 Pub.Service 3 3 3 28 Domestic Ruiral. 5 5 5 335 I340 Urban _ 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 I Page 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 10 LEA Motor Petroleum Total Non- Total Row Caso- Kero- Distil- Residual Products Elec- C/ Cols Commer- C019 No. _ LPG Avgas line Avtur sene late Fuel Ol Incl. LPC Hydro&b tricity _ cial_ 9-10
I Indig.Prod 107 107 420 527 2 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 -223 Generationl 13 Energy Sector Use & Loss -5 -5 -5
14 Cousumption 4 9 92 49 19 188 11 37299 471 420 891 15 industryl I-ining 35 35 65 100 100 l8 O the r 2 33 11 46 15' 61 42 103 19 TransLport
20 Roadi 92 98 190 190 190 22 Air 9 49 58 58 58 23 Coastal 19 19 19 . 19 24 Other Sectors
25 Agr. 3 3 6 3 3 26 Commerce 1 1 4 27 Pub.Service 28 Domestic 7 1 5 5 1'ural 8 8 8 356 364 Urban 1 10 10 * .9 20 322 42
Note /a Onemetric ton of oil equivalent is defined as 10 million K cal 7b Calculated equivalent power plant input assuming 28% efficiency /c Calculated at 860 Kcal/kWh. ANNEX I Page 6 of 13 TABLE I. 4
ENERGY BALANCE - PAPL'A NEW GUINEA - 1980
(original. units) LA COL. NO. IFA COL. NO. 3 4a 4b 4c 4d 4e 4f PetroleumTotal. 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-ecia oa Co
l-TOE k. , E- - _.. Kwhr. M_ Kwhr. O OINLS OIL .UIVALLT
1 Indig.Prod 316 90 434 524 2 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 1 IJste & LosssN
Total Final 4 11 117 60 23 231 7 371 1196 473 434 907 14 Consullp t i on
15 Thdustr.
lNltriuiig 41 35 774 101 101 18 ()ther 2 38 7 40 164 54 48 102 19 Transport
20 Road 117 124 195 195 195 22 Air 11 60 57 57 57 23 Coastal 24 20 20 20 24 Other Sectors
25 Agr. 4 3 3 3 26 Coolmmerce 2 2 82 9 9 2 7 Iiib. Service 1 1 59 6 6 28 DIomestic Rural 10 8 8 363 371 Ilrb}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 10 IEA M4otor Petroleum Elec- Total Non- Total Row Gaso- Kero- Distil- Residual Products Hydro triCi- Cols Commer- Cols No. LPG Avgas line Avtur sene late Fuel Oil Incl. LPG /b t c 3-8 cial 9-10 _
I Indig. Prod 90 90 434 524 2 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 Sector Use & Loss -4 -4 -4 14 Total Final Consumption 4 8 90 49 19 195 6 371 102 473 434 907
15 Industry Mining 35 35 66 101 101 18 Other 2 32 6 40 14 54 48 102
19 Transport 288
20 Road 90 105 195 195 195 22 Air 8 49 57 57 57 23 Coastal 20 20 20 20 24 Other Sectors 25 Agr. ~~~~~~~~~~3 3 ,3 3 26 Commerce 2 2 7 9 9 27 Pub. Service 1 1 5 6 6 28 Domestic Rural 8 8 8 363 371 Urban 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 Calculatedequivalent power plant input assuming 28% efficiencyor 3070 Kcal/kWt, {c Calculated at 860 Kca1jkh, ANNEX I Page 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 10 IeA Motor Petroleum Elec- Total Non- Total Row Gaso- Kero- Distil- Residual Products trict- Cole Conner- CoUs No. LPG Aveas line Avtur sene late Fuel Oil Incl. LPG Hvdro/b tVrc 7c clal 9-l2
1 Indlg.Prod~ ~ ~ ~ ~~ ~d106 500 606 2 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 Sector Use &'Loss -7 -7 -7
Total Final ON 14 Conisumption 5 7 103 52 23 219 11 420 153 573 500 1073 1
15 Industry _- . _____ Mining 50 5 55 104 159 159 18 Other 2 1 29 6 38 22 60 70 130 19 Transport 0
20 Road 103 114 217 217 217 22 Air 7 52 59 59 59 23 Coastal 21 21 21 21 24 Other Sectors 25 Agr.5 26 Conunerce 2 2 9 5 5 27 Pub.Service 1 1 6 ll 28 Domestic Rural 999 399 408 Urban 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 I Page 9 of 13
TABLE I.7 Forecast 1990 ENERGY 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 1901 I'aolftlWtf 304 112 ~~~~~~1121902 r ;,;as 304. 302 304 606 561 1167 7 .120 66 29 339 12 573 877 877 3177 - -18 !-.178 1 --178 1:vSyf.t~n R.q. _ 304 112 12 7 120 66 29 339 12 join m5
il<....-304f,,eratf-)n...... 8 -997 -72 -7 2 -475 218 -561-304 -561
- ~~~ ~~~~-9 -9 ~~-9 Tjt.t i i.:a] Consa. 0 13 12 7 120 66 29 267 12 501 526 0 209 735 561 1f2.j Tt i: I .l cons. _f
12.,;1r. 13 8 1 173 7 80 13 8 80 138 218 218 1 9529 42 34 76 88 .164
is., -. ~ 120 146 266 266 266 266 Ai, ~ ~ ~~~~~~~~~766 73 73 v 73 '73 2.' I 22 28 28 28 Ai-. S: 5.r Agl. 5 ! 5 5 5 C.;1C S,erce 6 .3 3 3 13 1 6 16 2u,tiUc S.erv1ce 1 1 1 7 S a
12 12 12 12 435 447 IIr~~~~~~~~~~~~~~.sn 1 ~~~~~~~~~~~~~~~~~~~15 16 i . 17 33 33 71
L"t isctctc"i, 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%Zefflcj1uncy 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 I TABLE 1. 8 C Page 10 of 13 CONDENSEDENERGY BALAMCE Forecast 1990 (in thousandsof metric tonnes oil equivalent) Gas Case: (Offshoregas with ) .______Methanol ) Primary Gas Petroleum Solid Fuels & Products & .Total Non-Com- (Coal) NGL Liquids Total Hydro Electricity Commercial mercial Total
Production 798 798 304 1102 561 1663
Irnports 304 - 573 877 877 877 Exports -178 -314 -492 -492 -492 Total 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 & loss 0\ Total Final Cons. 0 13 513 526 0 209 735 561 1296
Ind us try
l'ning 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 I Page 11 of 13 CONDENSEDENERGY BALANCE Forecast 1990 (In thousandsof metric tonnes oil equivalent) Coal case
Primary Gas Petroleum Solid 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 1045 Exports Total Energy Req. 447 43 598 1088 1285 561. 1846
Transformations Elea. gener. -447 -43 -72 -562 -197 218 -541 -541 Other trans. En. sector use
6 loss -9 -9 .9 Total Final Cons. 0 526 526 209 735 561 1296
Industry
tilning 80 80 138 218 218 Other 42 42 34 76 88a 164
Transport 367 367 0 367 367
Other 37 37 37 74 473 547 ANNEX I TABLE I. 10 Page 12 of 13
CONDENSEDENERGY BALMNCE Forecast 1990 (in thousands of metric tonnes oil equivalent) (Businessas usual)
Primary Gas Petroleum Solid 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 I Page 13 of 13 TABLE I. 11
PROJECTED ENERGY CONSUMPTION EXCLUDING COPPER AND EXPORTS
Rate of Growth 1980 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 energy required 464 555 733 3.6 5.7
Total final commercial energy 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 II Page 1 of 5
THE ELECTRIC POWER SECTOR IN PNG
1. In PNG the power sector comprises: The Papua New Guinea Electricity Commission (ELCOM), responsible for the public power supply; Bougainville Copper Ltd., (BCL), which generates a substantial amount of the power produced in the country for captive consumption, and private consumers who have provided their own generating plant in the form of small diesel generating sets.
2. The scattered islands and the extremely rugged and in some places inaccessible mountain ranges on the mainland eliminate any possiblity of a fully integrated power system. As a consequence, ELCOM operates three power networks which account for about 75% of its load: Port Moresby and environs; the Ramu system extending from Lae on the east coast to the Highlands, and Rabaul. It also operates small isolated networks 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 of Government 'C' class stations, of small size, and scattered over more than 100 locations. Map 16281 identifies ELCOM's operating centers, while Table II.1 gives the total installed capacity and generation in PNG at the end of 1980. BCL with 41% of capacity has contributed to 61%oof total generation (and consumption), while ELCOM with 51% of capacity has contributed to only 32% of generation. The class "C" centers represent 2.5% 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------Generation Hydro 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 Forest Products 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 II Page 2 of 5
3. As already mentioned (para.2)ELCOM operates three power networks which account for about 75% of ELCOM's load: the Ramu system, Port Moresby and environs, and Rabaul. For the Ramu system, the installed capacity is 65MW, but the reliable rating is only 25MW, or about 45%. At the run-of-riverRamu hydro station with 45MW installation,dry season reliabilityoutput is 11MW. Currently,one of the three units is shut down for turbine rebuilding for a year, a process likely to be repeated for the remaining two. Diesel capacity is limited by unit availabilitysince some units are often shut down for repairs. The system comprises a transmissionnetwork operating at 66KV (built for 132 KV) connecting Lae (the main industrial center of PNG), Goroka, Mount Hagen and Madang with the Ramu hydro station. Outage of a portion of this transmissionsystem has serious impact and necessitatessubstantial load shedding.
4. The Port Moresby system supplies the city itself and rural environs. Power is transmittedfrom the Rouna plants at 66KV. originallydesigned for regulated inflow by the upstream Sirinumu reservoiron the Laloki River, the hydroplantswere seemingly intended to provide power on the following basis:
Name Annual Firm Plate 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, due to the preceeding unusually dry period and mismanagementof the reservoir discharge, the Rouna hydro facilities have been operating for the past year at very limited load, in part to replenish the reservoir. Base load is being provided instead by the 20MW gas turbine installed at Moitaka late in 1979. Cost of expenditureson distillate fuel for the gas turbine was K 7 millin in 1980.
5. The Rabaul system on East New Britain Island with a demand of about 5.5 MW, is supplied by diesel aggregating 17 MW, which is in very poor condition. ELCOM decided recently to rehabilitatethe diesel facilities at substantial cost to enable the system to continue to be supplied until the new hydro station,Warangoi (10MW), now under construction,begins operation in 1983. 74 ~~~~ANNEXII Page 3 of 5
6. Capital investmentby ELCOM during the period 1973/74and 1980 is given in Table II.2 below.
TABLE II.2
ELCOM Investment 1973/74 - 1980
O(illionKina)
ConstructionExpenditure Investment CurrentPrices (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 II Page 4 of 5
Operating Statistics
7. Generation and sales statistics and other pertinent information for 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) 88.2 104.3 126.5 127.7 127.9 159.5 169.13 Maximum demand (MW) 44.0 48.2 51.5 61.0 64.4 79.9 79.05 Energy generation (Gwh) 279.6 309.0 334.1 175.0 369.8 440.1 465.0 Energy sales (Gwh) 255.8 274.0 302.9 153.33 338.8 379.6 409.3 System losses (%) 8.5 11.3 9.3 12.4 14.6 13.8 12.5 Load 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 per employee 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 of consumers per employee is low.
The system maximum demand (non-coincedential)was about 80 MW in 1980 as in 1979 reflecting the effect of suppressed demand and conversion from electricity tocsolar water heating. These two factors probably are responsible for the maller load factor, 592 compared with the earlier 66Z. - 76 - ANNEX II Page 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 at 8.9% and heavy industries at 14.8%. Out of the total sales, household sales constitute 29%, commercial/light industries 59% and heavy industries 12%. Although the number of domestic consumers increased by over 30% during this period, the total number of domestic consumers in 1980 was only about 32,000 representating about 5% of the total households but nearly 50% of the urban households. Table II.4 conveys some idea of the relative access to electricity supply in the Port Moresby area and that served by the Ramu network, constituting 63% of all ELCOMdomestic consumers but containing only a small fraction of the country's population, some 240,000 people.
The average annual domestic consumer usage was practically constant through the period at about 3,600 kWh, or 300 kWh per month, which is fairly high for a developing country, and is an indication of the urban enclaves characteristic of PNG.
9. In the Government's Energy Policy "White Paper" of 1978, some reservations were expressed concerning rural electrification (RE): that while it had become something of a password for development in the Third World, it was unlikely to be valid in the context of rural Papua New Guinea. The paper questioned the validity of the usual benefits attributed to RE, be*ter standards of education and literacy, lower population growth, reduced migration and improved quality of life in the villages, and thought they could each be achieved more readily by other means. The problems of providing RE in PNG cited, with some justification, were the economic impracticability of providing rural transmission or diesel generation given the isolation and distance of most villages and the terrain, and the ability and willingness of the villagers to pay for connection and usage.
TABLE II.4
Msttmatea Access to Electrec±tv I/ in Major Areas (as of Mid-1960)
Number of Estimated 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 III Page 1 of 6 The Transport Sector
1. Virtually all gasoline is consumed by road transport,but distillate is also used for marine transport, electricitygeneration, BCL own use (mostly graders, bulldozers,and concentratedrying) and other industrial use. Non-transportdistillate fuel use can, however, be estimated, and subtractedfrom total imports to give an estimate for fuel use in road and marine transport. Table III.1 below gives figures for fuel use in transport (excludingair) 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 Total Road (Estimated Road and Marine)
1970 76 75 151 1971 91 111 202 1972 97 116 213 1973 98 175 273 1974 102 91 193 1975 113 100 213 1976 113 98 211 1977 114 121 235 1978 118 136 254 1979 120 138 258 1980 117 154 271
From the table it is clear that 1970 appears somewhat atypical, as does 1973 for distillate. The latter figure may reflect inaccuracies in assessing BCL fuel use in its early stage, as well as possible errors in allocating fuel to different product categories in the import statistics.
2. Since we wish to test the hypothesis that the transport fleet is becoming more fuel efficient, the next step is to predict the fuel consumption implied by the vehicle stock on the assumption of unchanging fuel consumptionper vehicle. Table III.2 below gives vehicle stock data by category of vehicle. -78 - ANNEX III Page 2 of 6
TABLE rII.2
Registered Motor Vehicles by Vehicle Type ('000)
At 31 Dec. Car and Light Bus Other Station Wagon Open Van Commercial
1970 17.3 7.4 0.3 4.8 1971 18.9 8.5 0.4 5.5 1972 20.1 8.3 0.4 5.9 1973 19.0 8.7 0.5 4.9 1974 17.3 9.4 0.7 6.3 1975 17.9 10.6 0.9 6.4 1976 17.7 11.1 1.1 7.0 1977 17.2 12.7 1.5 7.1 1978 17.2 13.5 2.0 7.1 1979 17.7 15.0 2.4 7.7 1980 est. 18.7 16.9 3.1 8.5
Source: PNG StatisticalBulletin 25, March 1981.
3. Table III.3 gives estimates of fuel consumptionper vehicle, based on the 1979 Road Freight Transport Study. The percentage gasoline is based on Newcombe (1980).
TABLE III.3
Fuel ConsumptionPer Vehicle
Annual Distance Consumption Annual Cons. % Gasoline OOOkm litres/lOOOkm Kl
Cars and stationwagons 17.5 115 2.0 100 Light commercial 40.0 190 7.0 78 Bus 70.0 300 21.0 30 Trucks (i.e. all others) 50.0 175 8.8 0
This table gives the following prediction equation for fuel consumptionbased 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 regressingthe predicted fuel consumption on the actual fuel consumption. The results of regressing predicted on actual gasoline consumptionfor 1970-1979 are Predicted = - 18.2 + 1.18 actual r2 = 0.79 - 79 - ANNEX III Page 3 of 6
The fit is good and the slope is close to unity, as required. The slight departurefrom unity suggestsa decrease in fuel consumptionper annum per vehicle which is to be expected given the 72% real price rise of gasoline over the period (see Table III.4). One might have expected such a considerable price rise to have had a greater effect on fuel consumption,but it must be borne in mind that maintenanceand depreciationcosts are relativelymuch higher than fuel costs in PNG. Some evidence for this is providedby the high attritionrate of vehicles and their short life, shown in Table III.5. On average, it appears that cars last only 5-6 years and hence depreciateat twice or more the rate they do in developedcountries.
TABLE III.4
Gasoiine Diesel (Distillate)
fob price retail real price fob price retail real price price index price index toea/litre Index 1970=toealitre Index 1973=103
1970 7.9 100 1 8.4 107 * 2 2.8* 8.7 104 2.3 3 2.7* 9.0 103 1.9 7.5 103 4 12.6 111 11.4 121 5 (7.2*) 7.9 16.2 133 6.3 12.7 126 6 9.1 18.2 138 7.4 14.3 130 7 9.0 20.5 149 8.0 15.6 137 8 9.6 19.7 137 8.0 15.0 126 9 12.1 22.3 145 10.9 18.3 144 80 18.3 29.6 172 17.6 25.3 177 81 19.3 36.8 194 18.8 32.9 209
Notes: fob price: * Fiscal year average 1975 Jan, 1976 April, 1977 Tan., 1973 Feb, 1979 Jul-SeD, 1980 av.
Retail price: Gazetted
Real price index: 1970 = 100, retail price deflated by CPI for distillate,base is 1973 = 103. Figjres for 1981 assumes 10% inflation1980-81. - 80 - Ax II
PageL oL
TABLE III. 5
.kttritionRate 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 23 1.977 1982 - 544 2526 20 6443 2057 4386 21 1.978 1928 - 266 2194 17 6003 1261 4742 22
Source: Summary of Statistics, 1978. ANNEX III Page 5 of 6
4. The figures for estimated distillate consumptionin Table III.1 are derived as a residual after deducting other identifieduses. Since the original figures for distillate are themselves subject to considerable uncertainty,they must be treated with caution. Omitting the figures for 1973, which seems particularlysuspect, the regressionequation 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 the figures for actual diesel consumption are not available. The average ratio of predicted to estimated is 88% (excluding1973) and it could be argued that 88% of diesel is for road transportuse. Newcombe's estimate is 80%, and if we accept 84% as a compromiseestimate, then the equation could be rewritten
predicted = - 7.2 + 1.07 (0.84 estimated) r2 = 0.60 again suggestingthat the slope is above unity, as for gasoline. Again, this is consistentwith a fall in fuel consumptionper vehicle p.a., reflecting greater efficiencyand a response to higher prices. This consumption response has been less strong than for gasoline, but trucking demand is presumably less price elastic than personal travel demand, and the effects of improved roads have probably had a greater effect in lowering transportcosts for heavy vehicles than for lighter cars.
5. Thus, transport fuel use has beep growing less rapidly than the vehicle stock, which shifts the problem of explaining transport fuel growth back to one of accounting for the growth in commercialvehicles in a stagnant economy. The GDP data show that the share of GDP at current factor cost generated in the transport sector fell from about 6.0% at the start of the decade to about 4.5% at the end, suggesting that the transport sector grew, if anything, less quickly than the stagnant economy. It is hard to reconcile this data with the growth in vehicle stock and fuel use. Moreover, taking the tonnage of exports of coffee, cocoa and tea as a measure of transport demand from the Highlands,the growth averaged 4.7% p.a. over the decade, somewhat below the growth in distillate consumption,but still higher than the growth in GNP.
6. Several explanationsare possible. First, the transport component in GDP has been increasinglyunderestimated, and transport demand has been growing at a moderate rate. Second, personal mobility has probably been increasing (bus numbers have risen very rapidly), reflecting a change in consumptionhabits towards more fuel intensive goods (transportservices). Third, farmers may prefer to spend windfall gains on vehicles rather than alternativeconsumption goods, and then find both productiveand consumption uses for them.
Implications
7. Transport fuel use constitutesthe major oil demand, and, of the various oil users, is the one for which there are fewest alternativenon-oil based fuels. Future oil demand will depend critically on future transport demand. 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 populationwould rise at 7.5% 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, assuming a slow growth rate of 3% p.a. in per capita energy consumption.
8. This projectionpossesses little credibility,as it is difficult to believe that either urban migration will continue at past rapid growth rates in a stagnant economy, or that new migrants will enjoy the same fuel use as the current average, which is greatly increasedby the presence of expatriates and commercial/industrialdemand.
9. It would seem more likely that transport demand will grow in line with economic activity as a whole, possibly with an elasticityof above unity. At the moment transport use is very expensivebecause average vehicle life is so low. Table III.5 shows that the vehicle death rate is more than 20% for commercialvehicles, or, as a ratio to stocks of 3 years earlier, nearly 30%, suggestingan average life of less than 4 years. Clearly, the amortizationcosts are considerable. If maintenance and driving habits improve, operating costs will decrease, and presumablyincrease vehicle use and perhaps ownership rates. - 83 -
ANNEX IV Page 1 of 1
PRELIMINARY ESTIMATE OF HYDROELECTRICPOWER POTENTIAL 1/
(Schemes of greater than 50 MW and costing less than $600 / KW)-
RIVER POWER DEVELOPMENT POWER OUTPUT BASIN B Nev.', Total
Kikori Lower Waga 45 Upper Mubi 800 Lower Mubi 2500 3700
Purari Kondiu-Asaro-Wahgi 1350 Tua 2950 Pio-Purari 1700 I Aure 130 Lower 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 HydroelectricPotential of Papua New Guinea, Australian Department of Housing and Construction,April 1974. 2/ Only the most promising schemes are listed here. Others may also be identified in the course of preparing an inventory. ANNEX V Page 1 of 1 COAL OCCURRENCES IN PNG
Rank Chemistry Dip Volume Transport Ease of Exploration Mine Method Transport Potential Potential 1980's
Finschhafen !Lignite? ?Shallow Small Road to Finschhafen, Easy Small None sea to Pom
Kabwum Lignitic ? ?Shallow ?Small Road to Coast, sea Relatively Small Little to Pom easy
Pindiu Sub-bituminous Moisture 19% ?Shallow 40-50 Construct road to Medium Good Good Ash 9.4% million coast, sea to Pom VM 40.2% tonnes FC 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 Little shallow draught vessel
Hegigio Sub-bituminous Lignitic ? ? Small Road construction in Extremely Small None (Cannel) extremely rough difficult terrain, ? shallow draught vessel to Pom
Hohoro ? ? 10 -30 ?Large Adjacent to coast, Easy Good Good shallow draught vessel
Lower Purari Sub-bituminous See Table 2 20 0-300 Large Shallow draught River vessel Medium V. Good V. Good -85 - ANNEX VI Page 1 of 1 Organizational Chart of DME as of Novemiber1981
-{ ~~Minister-of DME
Secretaryof ODME
Policyand Planning
Geological Bureau of F National Survey Water Resources Weather Mines
Energy Planning Unit (EPUI
ELCOM XiLands Finance, DME, NPO, 2 PrivateSector)
World EBank-23726 - 86- ANNEX VII Page 1 of 10
CONSUMPTION,PRICE AND IMPORT COST DATA
1. Data Sources
For Petroleum Products
1969/70 - 1975/76 Trade Statistics (Heavy distillate allocated to residual fuel oil)
1975 - 1980 Energy Planning Unit data, based on trade statistics.
These data are presented in Table VII.1 below and are compared with the data from the UN 1979 World Energy Statistics in Table VII.2.
For Electricity:
Production 1969/70 - 1978 are taken from UN 1979 World Energy Statisticsare shown in Table VII.3. These correspond closely to those figures available in the Summary of Statistics,1978, which in turn appears more comprehensivethan ELCOM figures, since they systematicallyinclude Government production in "B" and "C" centres, and the private sector (BCL and PNG 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 consumption figures. 1980 figures come from ELCOM and EPU. Sales figures 1969/70 - 1972/73 come from the annexes to the Bank's Second Power Project, presumably from ELCOM, and later figures come from ELCOM. Different documents from ELCOM and EPU give different figures for some years, but it is hoped that the figures 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 consumptionat 16 MJ per cap/day for rural households and 6 MJ per cap/day urban households has been taken from Newcombe et al Energy for Development: the energy policy papers of the Lae Project, 1980. p. 189.
These raw data for fuel consumptionare then used to build up energy balances (Annex I) for '1970' (average of 1969/70 and 1970/71), '1975' (similarlyan average of 1974/5 and 1975/6), 1979 and 1980, allocating fuels to end use as explained in Annex I and the text. TABLE VII.1 ANNEX VII Page 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/ Oil ______Distillate1/ Residualfuel
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/kWhr 2/ 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 VII Page 3 of 10 COMPARISON OF UN DATA WITH BANK DATA ON PETROLEUM PRODUCTS ('000 metre tonnes)
Year Avgas Motor Avtur Distillate Residual Total Liquids LPG Gasoline 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 VII Page 4 of 10 ELECTRICITY PRODUCTION AND USE
Million KWhr Total Electricity Public Electricity BCL BCL Losses Domestic Thermal 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 VII Page 5 of 10
TABLE VII. 4
ESTIMATES OF DOMESTIC WOODFUEL CONSUMPTION
Year Total Urban Woodfuel Consumption Population 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 historicalseries on retail prices for energy products are presentedbelow in Tables VII.5 and VII.6. TABLE VII.5 PAgE 6o1 Page 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 55.5 129.9 130 131 140 394 423 680 789 cif 251 255 272 437 499 850 914
Avgas fob 56.8 62.9 158.5 146 170 174 204 275 848 736 cif 157 187 194 227 290 836 754
Mogas fob 43.5 47.1 133.2 146 155 153 183 231 371 378 cif 157 179 169 204 250 391 402
Avtar fob 33.0 37.3 115.4 113 125 125 150 246 356 355 cif 124 141 144 172 261 377 378
Kero. fob 37.1 39.6 107.3 124 131 125 140 205 353 372 cif 136 146 144 161 223 375 396
Distil fob 32.3 30.3 98.4 104 112 121 135 184 317 328 cif 115 129 141 157 202 338 352
Res. fob 15.6 13.1 61.1 77 70 79 78 104 159 212 cif 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. 1975-81 data comes from EPU Energy in Papua New Guinea 1981, and appears consistent where it can be checked against the Bank's estimates of c.i.f. products (landed at Bougainville). The only exception appears to be the figures for Avgas in 1980 and 81, where the posted prices were closer to $620. However, since Avgas has such a small overall share this should make little difference to the estimated import bill. -92- ANNEX VII Page 7 of 10
TABLE VII-6
ELECTRICITYTARIFF, PORT MORESBY
Domestic General Max Energy Fuel Cost Index of t/kWh Demand Charge t/kWh Real Domestic K/KW t/kWh Diesel GT Electrici.ty Price. 1971 = 100
1970 2.5 3.05 2.6 1.91 1971 2.6 3.2 5.5 1.50 100 1972 2.6 3.2 5.5 1.50 94 1973 2.6 3.2 5.5 1.50 2.2 90 1974 Nov. 3.9 3.9 8.5 1.44-0.64 3.5 105 1975 3.9 3.9 8.5 1.44-0.64 4.0 97 1976 5.5 5.5 10.5 1.8 - 0.8 4.6 126 1977 5.5 5.5 10.5 1.8 - 0.8 4.9 122 1978 5.5 5.5 10.5 1.8 - 0.8 4.6 118 1979 Nov. 8.5 8.2 ? ? 5.8 168 1980 8.5 8.2 ? ? 8.2 10.7 150 1981 June 10.8 10.8 discontinued 10.1 13.1 173* 1982 Jan. 11.5 11.5
* Assuming 10% inflation in 1981.
Notes: Figures for domestic consumers are at the lowest rate (above 190 kwhr/ month until 1980, then above 40kwhr/month). The maximum demand tariff Kina/Kw per month maximum 30 minute demand was discontinuedin June 1981. For customers on this tariff the marginal costs (energy charge) decreases to the lower figure shown above 5GWhr/month. The fuel costs for diesel generatorassume 30% efficiency,with 13% transmissionloss; for the gas turbine at Moitaka 23% efficiency. Distillate costs are estimates of the pre-tax wholesale delivered prices. ANNEX VII Page 8 of 10
Forecastingthe 1985 Import Bill
3. The product prices were forecast on the assumption that product prices grew at the same real rate as oil itself,which, given the considerable fixed refinery cost component,may overstate the future c.i.f. prices. The assumed c.i.f. prices in constant 1980 US$ are shown below.
TABLE VII.7
1985 Product Price Forecasts (1980 US$/ton)
Central Low High LPG 950 850 1050 Avgas 550 430 800 Mogas 480 420 500 Avtur 440 390 500 Kerosene 440 390 500 Distill 400 370 470 Fuel Oil 220 200 240
Coal c.i.f./TOE 75
These figures can now be used to project the import bill.
TABLE VII.8
1985 Forecast Import Bill (1980 US$ Million)
Central Low High Forecast
LPG 4.75 3.4 6.3 Avgas 3.85 2.2 7.2 Mogas 47.04 37.8 55.0 Avtur 22.0 18.3 34.0 Kerosene 9.68 6.6 13.0 Distillate 136.4 85.5 195.0 Fuel Oil 62.7 31.4 72.0 Coal 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 StandardDeviation) 14 - 27% ANNEX VII Page 9 of 10
1990 Petroleum Product Prices
4. The Bank's projected crude oil price rises by $40 (1980) per tonne between 1985-90. On the assumption that refining and transportmargins do not rise in real terms, the projected 1990 product prices are all $50/tonne higher than in 1985. The projected methanol price is based on scenario 2 of the Bank-s Methanol Study which assumes that there is no real price increase for methanol after 1980, as opposed to Scenario 1, which assumes 2.5% p.a. real escalation. It is thus the more conservativeassumption. Coal is assumed to rise at 2% p.a. in real terms. The 1981 estimated deliveredprice to BCL was $48/tonne,and to Port Moresby $70/tonne.
The f.o.b. price of condensates is assumed to be the world market price for gasoline, less transport costs. The Bank-s Methanol Study projects the 1990 gasoline price as (US$ 1980) $474/tonne,and hence condensatesare valued f.o.b. at $425/tonne. The price assumptions are summarised in the table below:
TABLE VII.9
1990 Price Assumptions 1980 US $ tonne
LPG (import parity) 950 Avgas 600 Mogas 530 Avtur 490 Kerosene 490 Distillate 450 Fuel Oil 270 Coal: BCL 60 Port Moresby 85 Methanol f.o.b. 208 Condensatesf.o.b. 425 ANNEX VII Page 10 of 10 TABL.EVII.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
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