Papua New Guinea - Issues and options in the energy sector

Report No 3882-PNG Papua New Guinea: Issues and Options in the Energy Sector June 1982 Report of the joint ULMP/Mfdd Bank Energy Sector Assessment Program 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/World Bank 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 restricted distribution. Its contents may not be disclosed without authorization from 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 MAP S 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 relatively well-endowed with energy resources - hydro potential conservatively estimated at 14,000MW, gas reserves (from six discovery wells) already estimated at a possible 1.5 to 5.0 trillion cu. ft. with large sedimentary basin 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 consumption and 87% of all commercial energy consumption. Because of rising world oil prices and increasing demand 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 intolerable burden 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 fragmentation of the market, which leads to high investment and operating costs per unit of output. Careful planning is therefore essential to determine the appropriate options available for substituting imported petroleum products by indigenous energy sources. In recognition of this, the Government of PNG established in 1978 an Energy Planning Unit (EPU) in the Department of Minerals and Energy (DME) and by 1979 had issued a "White Paper" outlining its energy objectives and policies. The "White Paper" emphasized the role of renewables in alleviating PNG's energy problems, particularly ethanol for the transport sector (which consumes 45% of all petroleum products), wood pyrolysis for the industrial sector and solar water heating and photovoltaics for 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 conventional areas of activity tended to be neglected and 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 substituting the oil used in power generation and where severe and widespread operational and financial difficulties were being experienced. More recently, some attention is being paid to the prospective use of onshore and offshore reserves of natural gas, to hydro development and 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 recommendations for developing and strengthening the energy planning process. In addition to institutional strengthening there 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 electricity consumption (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 electricity supply 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 electricity because ELCOM, beset by its own management and financial problems, has not been able to fulfill its role adequately as a public utility with the responsibility of 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 Consumption Pattern, 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 transformation losses 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 electricity produced. 4/ Estimated. Energy Forecast 1985 and 1990 Demand 1.08 Forecasts made by the Bank suggest a GNP rate of growth of 4% per annum over the decade, perhaps higher in the early part as Ok Tedi starts production. (By 1986 this mine might account for an additional 10% of GNP, suggesting that growth elsewhere may be below 4%.) This is comparable to growth over the past decade, during which energy demand grew steadily. Based on assumed sectoral growth rates, projections made 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 Consumption Pattern 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/ Historical growth rates in final energy consumption during the seventies are as follows: 1970-75 9.3% (BCL started operation in 1973) 1975-80 3.6% 1970-80 6.4% Supply 1.09 Not much can be done on the supply side to alter the picture for 1985 due to the short-lead time available. However, the mission assumed that BCL may, by then, switch to coal-fired thermal plant (2 x 45 MW), instead of continued reliance on fuel oil. The options available for 1990 are numerous and for the purpose of illustrating a few of these options and the magnitudes involved, three preliminary supply 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 conservatively estimated 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-river schemes have been implemented. One difficulty in planning hydro development is 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 potential hydro sites for which no records exist. Attempts have been made to synthesize data from general rainfall records, the characteristics of similar streams, and from gauges installed in the relatively short period when any given project is under consideration. Hydro plants installed on the basis of such inadequate data have not met expectations and 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 investigation of other possible sites for feeding the Port Moresby/Ramu grids. 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 insufficient to 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 recommends a reappraisal of the 25 MW coal-fired thermal plant proposed by consultants C.T. Main, who were commissioned by DME to investigate the options for power supply in the Port Moresby area. (iii) Third, by use of natural gas resources, particularly the Barikewa reserves for the Ramu grid but also, possibly, the Pasca/Uramu reserves for the Port Moresby grid. (iv) Fourthly, by using wood-wastes for power generation for the Ramu grid, which the mission considers worthy of  -9 further examination, although the mission concurs with ELCOM's views that wood supplies in the Port Moresby area are insufficient to sustain even a 10 MW wood-burning plant on a long-term basis. (v) Since other mining metallurgical enclaves (besides Ok Tedi) are being considered the mission recommends that an inventory of all major hydro sites (over 50MW) be compiled and from this list preliminary feasibility 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 Substantial exploration 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 cataloging all 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 hydrocarbon fuels in the economy, coupled with the availability of gas, calls for a greater sense of urgency in using this valuable resource. As the situation now stands, the oil companies have little incentive to develop the proven reserves for domestic use for power considering the small fragmented demand centers and degree of industrialization of the country, unless they can be associated with export-oriented industries. The Government should 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) consideration should be given to providing incentives to the oil companies for developing such 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-offshore gas fields, mainly to establish the feasibility of development of each of the individual gas fields, and evaluate a combination of gas utilization options including: (1) a gas-fired power plant using onshore gas from Barikewa with transmission to 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 condensates and 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/urea production. Coal 1.20 Coal occurrences have been found in the Morobe and Gulf Provinces and near Madang but no active follow-up work has been considered necessary to firm up reserves. They have generally been small deposits of low grade coal with seams dipping at moderate angles. From the meager data available, it is likely that technically recoverable 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 geological work 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 assistance will be available. Geothermal 1.21 There are surface evidences of hydrothermal activity in the form of seeps and geysers at temperature of 900/950C, particularly in the Rabaul, Hoskins and Talasea thermal areas of New Britain and the Deidei and lamalele thermal areas of Fergusson Island. As electricity consumption in these areas is small and there is no consumption of steam for process purposes, there is no urgency in developing the potential, but some priority may be given to identifying the potential of the Rabaul thermal areas. Renewables 1.22 PNG has had a comprehensive program 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 disappointing results. The eventual potential for energy production from these sources might be immense, but their technical and economic viability needs to be proven with minimal expenditures, particularly in the context of potential development of oil and gas. (a) Ethanol: Considerable emphasis has been placed on developing ethanol from biomass as a substitute for motor fuel. A cassava- based project at the Baiyer River is under development at 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/annum molasses-based project in the Ramu Valley seems economically attractive, but it is unlikely that any other new projects will prove viable. The economic justification for 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 unrealistic and has been reduced first to 36 million and more recently to 10 million. The Government should carefully review the economic justification of any further investment in ethanol projects; (b) Wood: Wood resources are tremendous (covering 40 million hectares) and fuelwood contributes about 40% of total energy consumption. Nearly 95% of the fuelwood is consumed in households, the remaining 5% being consumed in the industrial sector, particularly agricultural processing where it accounts for about 62% of all energy use It is expected that the consumption of 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. Gasification has only been attempted on an experimental scale. Studies for the utilization of the considerable wood wastes through wood gasification and steam generation should continue to be made. The possibility of 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 generation has been considered by ELCOM and rejected, but may be worth a second look, particularly at Lae-Bulolo. 1.23 With respect to other renewables: (i) The mission supports EPU's decision that no 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 encountered in using the wood wastes in the Lae area. (iii) Solar water heating has had great success in residential and commercial buildings and is economically viable. The mission commends the measures taken by Government for this purpose, especially the provision of tax incentives for the installation of solar water heaters. (iv) Photo-voltaic cells are very expensive and are not economically viable at present given the very low consumption of 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, relatively low, levels of funding may continue. Institutional Issues 1.24 In the petroleum subsector, the Geological Survey Division within the Department of Minerals and Energy has responsibility for technical advice on all matters concerning oil and gas, coal and geothermal energy. 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 expatriates and PNG nationals, all geologists and geophysicists, look after both minerals and oil and gas. There is no staff experienced in petroleum matters. In view of the importance of oil and gas, the Geological Survey Division ought to be strengthened by drawing on outside expertise to oversee the implementation of the Government's exploration policies and eventually, as delineation of reserves progresses and commercial discoveries are 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 difficulties and 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-fuelled turbines. 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 recruited for a five-year contract, four technical staff 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 subsectors and the Forestry 1/ Exemplified by turbine breakage, siltation, drought, etc.  - 13 - Office of Department of Primary Industries (DPI). EPU's expertise should be diversified so that it can handle these 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 Planning and Policy Division. Priorities for Action by PNG 1.27 Among the various recommendations made 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 exploration activities in an effort to firm up reserves of oil and gas and reach agreements on the development of already discovered gas fields (paras. 1.19 and 3.24). (b) Completion of a gas utilization study on the onshore - offshore gas fields (paras. 1.19 and 3.22). (c) Urgent reconsideration by ELCOM of a 25 MW coal-fired thermal plant for Port Moresby and, if viable, development as soon as possible (paras 1.17 and 3.11). (d) Creation of a group of outside specialists for 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) Redefinition of 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 implementation of renewable energy projects and conservation measures (paras. 1.26 and 5.06). (f) Confining work on ethanol to the Ramu project and to critical evaluation of all other proposals (paras. 1.22 (a) and 3.37). (g) Investment in gauging stations on small rivers in PNG (paras. 1.16 and 3.07). (h) An inventory of all major hydro sites (over 50 MW), from which 3-4 large hydro sites should be selected for feasibility studies for possible use by metallurgical enclaves (paras. 1.17 and 3.14).  - 14 - (i) Finally, least cost studies of the various alternatives of expanding the ELCOM power system be continued over a longer (15- 20 years) time frame (paras. 1.17 and 3.16). Framework for Technical Assistance 1.28 To assist the Government in implementing many of the recommendations made above, the mission strongly recommends that technical assistance financed 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 utilization study on the onshore-offshore gas fields, possibly within the context of the on-going petroleum exploration project; (b) US$1-1.5 million for an inventory of major hydro sites and preliminary feasibility studies of 3-4 large hydro sites to determine their potential for use by an enclave metallurgical operation; (c) US$1.0 million for financing about 75 new gauging installations on small hydro sites for which there are no flow records; (d) A series of wood and wood-waste utilization studies; (e) Delineation work on coal reserves for domestic use in thermal power plants; and (f) Institutional strengthening for EPU to enable it to function as an overall energy planning agency.  - 15 - CHAPTER II ENERGY CONSUMPTION AND PRICING Consumption Overview 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-commercial energy, mainly woodfuel. Per capita consumption of total energy is approximately 2.8 barrels of oil equivalent (BOE), which is the same as in middle income developing countries in Asia (Indonesia 2.2 BOE, Thailand 2.7 BOE, Philippines 2.8 BOE). Annexes I and VII offer detailed historical data on energy consumption and 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 Commercial Energy/GDP .23 .28 .50 Final Commercial Energy/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 consumption in 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 declining as a proportion of total consumption, woodfuel accounted for an estimated 38% in 1980 as against 41% in 1975 and 56% in 2970. In absolute terms, woodfuel consumption grew at 2.4% durin'g the seventies which is close to PNG's population growth rate of 2.3% p.a. 2.03 Commercial energy consumption increased from 44% of total energy consumption in 1970 to 62% in 1980, i.e. at a growth rate of 10.2%. Since 87% of all commercial energy consumed comes from petroleum (the rest being supplied by hydro) this in turn reflects an increased dependence on oil imports. Petroleum consumption for power generation has increased from 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 consumption of 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 population grew at 2.3%), and per capita GDP therefore stagnated during the decade. Despite this, energy consumption has continued to grow faster and the ratio between energy consumption and GDP has therefore increased, making PNG more energy intensive. 2.05 The most dramatic increase in energy consumption occurred in 1970-75 when the Bougainville Copper Mine (BCL) started production. BCL imports oil to generate electricity which is used primarily to produce concentrate from low grade ore. Table 2.2 shows the sectoral consumption of primary commercial energy including and excluding BCL, 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, including woodfuel consumption, is given in Annex I (Tables 1.4 and I.5) and is summarized in Table 2.3 below. Of the total primary energy consumed, 524,000 TOE or 46% was indigenous and the remaining 619,000 TOE or 54% was imported petroleum. 83% of the indigenous energy production was 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 Consumption Pattern in PNG in 1980 ('000 tonnes 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 transformation losses of 236,000 TOE. 3/ Does not include petroleum products used for power generation equivalent to 248,000 TOE, included in the electricity produced. 4/ Estimated. Sectoral Pattern of Energy Consumption Transport 2.08 Estimates of consumption of fuel in the transport sector and 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 Statistical Bulletin, March 25, 1981. These members include motorcycles and 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 consumption in power generation and industry. 2.09 The growth rate of vehicle population excluding motorcycles and tractors has been around 4% between 1971 and 1980, whereas the transport fuel consumption has grown at only 3%. These estimates suggest that fuel consumption per vehicle has been falling over time, a response both to steeply increased gasoline prices and introduction of smaller, more- efficient cars. This ratio might have declined further were it not that maintenance and depreciation costs are relatively much 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 consumption per 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 transport sector 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 alternative non-oil based fuels. It is also the sector in which demand is likely to increase because of increasing urbanization and rural development. Industry 2.11 The largest single fuel using industry is Bougainville Copper 1/ Some evidence for this is provided by the high attrition rate 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 industrialized countries.  - 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 conveniently divided into two; the processing of agricultural products, and a heterogeneous collection of other industries. Of the 155,000 TOE final commercial energy consumption in the industrial sector (Table 2.3) BCL consumes 101,000 TOE (65%), while agricultural processing companies and the other non-mining industries consume the other 35%. These three subsectors are discussed below. Bougainville Copper, 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 distillate were 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 electricity generation done for BCL (by Bechtel and Minenco Pty.) have been completed, both of them recommending a 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 commissioned in 1982, as a stop-gap while decisions on hydro power, and the possible switch to coal firing or new coal-fired generating plant, are made. Negotiations between 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-river 1/ 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 dependence on 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/tonne of oil equivalent), substantially below the import price of residual fuel oil in 1981 ($220-$243/tonne of oil equivalent c.i.f.)2/. 1/ A dam could possibly be built, but requires further investigation. 2/ Coal import prices f.a.s. Loloho (the site of the generating station) were estimated at K32/tonne by Bechtel (and perhaps as low as K24) in 1981, based on an Australian East Coast price of K19-22/tonne and shipping costs of K6-9/tonne in 25,000 dwt ships or K4.6-6/tonne in 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 considerable fall in heavy fuel oil demand, and some switch to woodfuel. Estimated oil consumption in industries other than agricultural processing in 1980 is about 22,000 TOE. Consumption figures 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 agricultural processing of 4.3% of gross output (Table 2.6). Agriculture 2.18 Agriculture accounts for about one third of GDP, but a very small fraction of total energy use. Its direct demand for 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- agricultural purposes. The processing of agricultural products is, in contrast, quite energy intensive and has already been dealt with above (para. 2.16); agricultural products also require transport, so that indirect energy consumption use is considerably higher. Although agricultural output 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 consumption remains very small. Households 2.19 As noted earlier (para. 1.03), PNG is characterized by the 'enclave' type of development, where the urban enclaves account for nearly all the commercial energy consumption and 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-commercial sources, 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 (363,000 TOE non-commercial and 8,000 TOE commercial). The urban population at 0.4 million (13%), consumes 45,000 TOE (25,000 TOE non-commercial and 21,000 TOE commercial). Per capita consumption of 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 consumption of 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 consumption of fuelwood comes to approximately 6.6 kgs per day  - 24 - and this is close to the figure for other developing countries (such as Indonesia where 6 kgs per household per day is consumed in rural areas). In the urban sector, kerosene, electricity and woodfuel are used for cooking and electricity and kerosene are used for lighting. 2.20 The household consumption of kerosene for lighting in the rural areas comes to nearly 22.5 litres/year which is substantially lower than the household consumption in middle income developing countries and closely approximates the level of consumption in the poorer developing countries. This is one of the reasons why rural electrification programs are not likely to be viable in the rural areas of PNG unless they are combined with the introduction of 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 financially self-sustaining, networks (Annex II). 2/ Category III refers to very small ELCOM stations (Annex II). 2.22 The present tariff structure together with the introduction of 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 installation of the new more efficient gas turbine in Port Moresby: Table 2.8 Elcom Production and Supply Costs, 1981 Specific Efficiency 1981 Operating Costs (t/kWh) Fuel cons. (%) Fuel Cost System Delivered (litre/kWh) (t/ltr.) Fuel Other Loss (x) Cost Port 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 considerable out-cry against the sudden sharp increase in tariff levels, coupled with increasing complaints about the quality of service. Commercial and industrial consumers are, therefore, increasingly tending 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 subsidized motor spirit, distillate, and lighting kerosene in remote areas, ensuring that prices were no higher than 12 toea/litre above main port prices in 1977/78, and somewhat higher in later years (16 toea/litre in 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 (Amendment No. 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 submissions made by the distributing companies (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 diversified energy resources. The largest resource is the hydroelectric potential created by the mountainous topography and 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 14,000-21,000 MW 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 discoveries have been made, both onshore and offshore, with gas reserves conservatively estimated at 1.5 - 5.0 TCF and condensates at over 60 million barrels. However, considering the large area underlain by sedimentary rocks with potential for petroleum and natural gas, past exploration has been quite modest and these hydrocarbon resources are essentially unevaluated. Oil companies have not accelerated their 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 manifestation of geothermal energy. Coal occurrences have been reported in the Gulf Province and near Lae. The country's resource base provides a wide variety of long-term options for its energy planners. These are discussed in the following sections. 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 attributed to weak management, poor planning and poor operations and maintenance. The large increase in oil prices and the series of problems stemming from unexpectedly poor hydrological conditions affecting the hydro plants have accentuated the problems. 3.03 ELCOM and its consultant, Charles T. Main, agree on a probable load growth averaging approximately 7% 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 acceleration of 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 industrial sectors;(iii) a considerable number of commercial and industrial consumers 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/ Installed hydro capacity in PNG is about 100 MW.  - 28 - forecast since they will also have captive plants. 3.04 Although there are many potential hydroelectric sites (Annex IV), the fragmented nature of the country, and limited demand in any one locality, mean that the development of 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 utilizing PNG's hydro resources. 3.05 A particular difficulty in planning hydro development is the lack of stream gauging records, particularly for the small rivers. The large rivers have been given more attention and gauging information is available or, in some cases, is in the process of being obtained. Some identification surveys of potential small hydro sites have been made employing elevations 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 preliminary plan for each station identified together with river flow characteristics. This gives a false authenticity to information that is highly uncertain. 3.06 Hydro plants installed on such a basis may not meet expectations, and minimum and average flows may be seriously below the amounts designed for, particularly in dry years. The provision of such facilities carries 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, representing the 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 supplementary diesel 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 development there is a 23 year gauging record, but located below the junction of the two rivers. For the Tua and Oreba sites, present gauging information is 3 years for one, about 13 years for the other. Rouna had a 23 year gauging record, but actual experience suggests 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 predicting hydrological performance as 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 development program 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 perceptions changed. The present status is: (i) Pauanda hydro (12 MW) on the Ramu system is under construction for commissioning in 1984; (ii) Warangoi hydro (10 MW) on the Rabaul system is under construction for commissioning in 1983; (iii) Rouna 4 (13.5 MW) for Port Moresby is in principle committed -- provided the investigation 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, consultants have recently identified the 42 MW Naoro-Brown river site. A feasibility study for the Brown River Basin has been commissioned by ELCOM. 3.09 As to the option of using gas for electricity generation 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 transmission line built to the Ramu grid at Mt. Hagen. Very preliminary cost estimates, including an 18 MW gas turbine, are about K 23 million (US$34 million). Part of the transmission line 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 irrespective of 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 increased as required by additional gas turbine installations at Barikewa. All of the four hydro schemes listed in para. 3.08 are run-of-river with 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, particularly in 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 substantial base load generating plant. The Pasca gas/condensate discovery some years back, located 80 km off- shore in the Gulf of Papua and 250 km up the coast northwest of 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 indicates that the economics of such an undertaking might be quite favorable yielding 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 facilities are needed as soon as possible. Therefore, ELCOM should pursue the possibility of installing a coal fired conventional steam thermal station. The logical size would be about 25 MWl/. If the unit cost is less than $1500/kw, then the cost per kWh of burning imported coal would be 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 increasing amounts in the future, due to hydrological uncertainties associated with small run-of-river hydro stations. 3.12 The gasification of woodfuels in large gasifiers suitable for direct use in gas turbines is still in the development stage; therefore, the possibility of 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-designed boilers 3.13 The Government s cautious approach to rural electrification and mini-hydro seems reasonable. It appears that photo-voltaic cells might come to have limited commercial application, predominantly for telecommunication but also possibly for lighting in villages, and in some other places for fans and pumps where the consumers are affluent. The outlook for wind generated power, however, does not appear promising on the basis of available meteorological data. 3.14 Besides Ok Tedi located in the westernmost part of the New Guinea Island near the Indonesia border which is being developed for gold and copper concentrates, based mainly on hydro power, other sites which might offer opportunities for 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 construction in India at an estimated cost of $1000/kw. It is understood that other countries such as Poland, E. Germany and France also manufacture standard sets in this range.  - 31 - nickel and cobalt mining, and (c) Porgera in Enga Province for gold mining. None of these potential developments are 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 inventory of all large hydro sites (over 50 MW) should be compiled and preliminary feasibility studies should be carried out on 3-4 sites selected from this list. Current work on a metallurgical resource inventory should be continued in parallel. 3.15 The Government is to be commended on its program for conser- vation of electricity, that is, the substitution of solar for hot 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 development of the power sector over a longer time frame of 15-20 years. In order to do this, however, studies on utilization of on-shore/off-shore gas fields, the setting up of thermal stations at Port Moresby based on coal, and at Lae based on wood- wastes/coal and the feasibility of large hydro sites, should be completed as a matter of priority. Oil and Gas 1/ 3.17 A significant amount of exploration work has been performed in the oil and gas subsector over the past fifty years, particularly since 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 geophysical surveys and drilling of wells. All data collected under these approved projects, including samples and cores and copies of all documents had to be provided to the Government. Under this arrangement, 28 wells were drilled, and 150 geophysical and geological surveys were completed 2/. In addition 30 wells were drilled prior to 1954, though very little information is available on these operations. About 30 wells were also drilled by private companies at their expense and partial data are available on 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 feasibility of 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 justification for a refinery until domestic oil discoveries had been proven. The mission concurs with this conclusion. 21 Robertson Research Consultants have 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 petroleum matters (generally referred to as Petroleum Resource Assessment Group or PRAG) and to provide for storage and documentation of 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 discoveries there: 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 confirmation well had a gas flow at an estimated rate of 17 million CFD, with a significant quantity 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 shallower water (30 feet) and therefore its exploitation may be more economic. The discovery well had a gas flow at 13-14 million CFD, and reserves are estimated at 0.2-0.4 TCF. However, the gas is dry and condensate reserves would be minimal. 3.19 The onshore discoveries are 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 delineation well 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 exploration work 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 discoveries in 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 discoveries are 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 production rate in excess of 120 million cubic feet/day (MMCFD) - roughly the heating equivalent of 1 million tons per annum of fuel oil.  - 33 - exploit these resources solely for domestic consumption 1/. But unless gas is used for power generation, dependence on imported oil is likely to increase over time. This is why a number of alternatives need to be examined whereby gas for power generation and industry becomes available at Port Moresby and other areas and the export sector ensures the development of 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 estimates and the other on gas utilization, both prepared in 1978, were made available to the mission. The resource estimates have been made by the group holding the exploration license, 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 unacceptable to very marginal economic returns. 3.21 A review of these reports suggests that (a) the recoverable reserve estimates are conservative, and (b) the three scenarios used in the utilization study do not cover all available options. The reserve estimates are conservative with respect to reservoir volume, i.e. porosity of the reservoir rock and the gas/water contact, liquid production potential at Pasca and recoverable fraction of in-place reserves. The earlier preliminary estimate of.l TCF and 60 + million barrels condensate recoverable made 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/condensate ratio 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 consumption of 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 electricity generation in 1980 is estimated at 247,000 TOE. 2/ "Reserve and Deliverability Report of the Pasca and Uramu Fields" and "The Commercial Utilisation of the North Delta Gas Resources in PNG - 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 substitute or extender. The dry gas could be subsequently produced 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 consumption and the remainder reinjected to 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 alternative scenarios, 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 development of the Pasca field and the consequent need for an in-depth gas utilization study which the mission recommends. If it proves possible to develop Pasca, the possibility of developing the nearby offshore Uramu field is enhanced. 3.23 The onshore gas discoveries at Barikewa and Iehi also offer interesting possibilities for development, the most important being power generation with gas turbines at or near the gas field and transmission to Mt. Hagen or nearby, for connection to the Ramu grid. The onshore fields can be developed by themselves without reference to the offshore fields or to export possibilities. One production well may be adequate to meet the thermal power component of the Ramu grid and could possibly be completed quickly. 3.24 What emerges, therefore, is that there are many options which these offshore and onshore gas discoveries provide, and the mission recommends that these should be taken into account in drawing up any medium-to-long-term energy plans. The mission recommends that the Government require speedier exploration and 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 occurrences have 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 Geological Survey Report "Coal Occurrences in 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-bituminous in rank. Reserve estimates have since been downgraded. (ii) Lower Purari and Hohoro areas in the south: Large reserves made these ocurrences prospective except for the fact that the seams dip and the area can become flooded quickly making exploration and mining difficult and expensive. The characteristics of 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 information available, it is generally agreed that technically recoverable 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 exploration of the Pindiu area, and technical assistance should be sought for this. 1/ The mission understands that there has been a moratorium on the issue of new mineral production licences because of personnel constraints in the Division of Mines.  - 36 - Geothermal Resources 3.27 Manifestation of volcanic activity can be found in many-parts of PNG, and considerable geological and geophysical work has been done to identify geothermal potential since 1950. A substantial part of this work has been done on New Britain and D'Entrecasteaux Islands east of Papua, which are held to be the most prospective. There are surface evidences of hydrothermal activity in the form of hot water seeps and geysers at temperatures of 900-950C, particularly in the Rabaul, Hoskins and Talasea thermal areas in New Britain and the Deidei and Iamalele thermal areas in the Fergusson Island of the D'Entrecasteaux group. 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 geological and geophysical work be done 1Y. As the electricity consumption in these areas (with the possible exception of Rabaul) is small and there is little or no consumption of steam for process purposes, there is no urgency in developing the potential, but some priority may be given to identifying the potential of the Rabaul thermal area. Renewables 3.28 The potential for energy from renewable sources is very large. A substantial part of the land area is under forests, estimated at 40 million hectares. Only a small part of this resource is being used presently. In addition, agricultural products 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 application of solar energy for heat and electricity becomes possible. However, wind and wave energy are likely to have negligible potential. Some of the more important renewables are 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 remaining 5% 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 systematic utilization is very difficult considering the 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 industrial fuel since it is easier to transport than wood, it is storable 1/ "Geothermal Investigations in Papua New Guinea" by G.W. Grindley and L.A. Nairn, August, 1974.  37 - and can be used in existing equipment with 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-sized material, 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 feasibility study to the construction of a small pilot plant at the University of Technology at Lae. However, the plant was dismantled in November 1981 and moved to the Dylup cocoa/copra plantation near Madang. 3.30 With the demise of the industrial charcoal program, focus was shifted to gasification of wood wastes from the Lae Sawmills estimated at 100,000 tons per annum. At present, there are no industrial scale gasifiers installed, though plans to put a gasifier/burner in the Lae Brewery, in place of the existing oil-fired boiler, are being implemented. Wood gasification for running of stationary engines might have a greater application since a number of diesel generating sets are operated all over the country. Many of these are in remote areas where it is difficult and costly to transport the diesel fuel, and woodfuel is available nearby. There is also the possibility of using woodfuel for steam and power generation in conventionally-fired thermal 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 considerable cost and pollution of surrounding areas. It is recommended that the possibility of using these wood wastes for steam/thermal power 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 development of ethanol production from biomass to substitute for transport fuel. A target of 130 m litres/annum production 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 development in the Highlands at Baiyer River. Government statements have emphasised the intention that ethanol production should be competitive in cost with fuel imports and further development of this project is contingent on its economic viability based on this criteria. 3.33 PNG experiences a fuel deficit and enjoys an agricultural surplus. However, this surplus rests largely on tree crop products and there is no history of commercial production of sugar or cassava. On the other hand, in general there is a reasonably abundant supply of cultivable land, and the availability of investment funds is a more important constraint than land supply in spite of the complicated problems associated with 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-product from this industry is expected to be the single most promising feedstock for ethanol production, in view of its low opportunity cost. At Baiyer River, local cassava varieties planted for the ethanol project are giving extemely impressive initial yields (70 tonnes/hectare). Naturally- occurring stands of starch-bearing sago palm (and of the nipa palm which yields a sucrose - rich sap) are extensive, but collection systems are likely to prove problematic. 3.34 The economic and financial viability of ethanol production in PNG will be far more location-specific than in most countries, because of the unusual lack of geographic integration. As Map PNG 16180 illustrates, the national road system and hence the market for motor spirit comprises a series of coastal towns or cities, each with its own hinterland road system, but only connected to each other by sea or air. The larger coastal towns land refined petroleum products directly from international vessels (Port Moresby, Lae, Rabaul, Madang, and Arawa Bay for Kieta), while smaller ports must rely on domestic coastal transshipment (e.g., Wewak). The consequence of this fragmentation of an already small national market for gasoline is to add significantly to the barriers facing any potential ethanol project, since production which exceeds the absorptive capacity of a small immediate market would have to bear the additional cost of coastal shipping to another region of the country. 3.35 As a result of these locational factors, the ethanol plants under consideration are mostly very small by world standards and unable to benefit from economies of scale. In addition, PNG's topography, poorly developed infrastructure and shortage of indigenous technical and managerial skills greatly increase costs of construction and operation of ethanol plants compared to countries like Brazil. The Baiyer River ethanol plant (capacity 8-10,000 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 particular project, 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 continuation would appear marginal at best. 3.36 Apart from production-side difficulties posed by high plant capital costs and technical uncertainties relating, for example, to the proposed sago palm components, the government's originally published ethanol targets have been recognized as over-ambitious. Quite apart from the technical problems, substitution of 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 substitution for diesel are severe. The government has recognised the problems involved in the original plans and is continuing to cut back the ethanol program radically. 3.37 Proposals have been prepared to add an ethanol plant to the sugar mill under construction in the Ramu Valley. Such a plant would enjoy a number of advantages unique within PNG. Capital costs for the ethanol project would be significantly reduced, especially on the 'front end', through sharing of facilities with the sugar mill. Much of the feedstock for the alcohol plant would be by-product molasses, 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 consumption in 1980 estimated at 117 million litres). A consultant's feasibility study for this project estimates an economic rate of return of 18%2/. If this is so, then the Ramu Valley ethanol proposals must be considered economically attractive. Other projects, however, are unlikely to prove economically viable unless world gasoline prices record further significant increases or considerable progress is made in reducing capital costs of small-scale ethanol 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 facilitated contracts between Appropriate Technology 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 cooperative to build a small scale demonstration biogas 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 inoperative for technical reasons. Although biogas is not seen as a major industrial energy source on a national scale, it does offer a means of producing energy at some sites, especially in remote areas, but 1/ Detailed analysis available in Bank internal report on PNG's ethanol projects, referred to in footnote page 37. 2/ Recent communication of EPU.  - 40 - this would necessitate further improvement in the digester design by the manufacturer. However, the mission believes that no additional effort by the EPU is required to facilitate introduction of this technology which has only limited application in 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 3,000-4,000 per installed kw, the unit is subject to fluctuating water availability and 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 Development Bank, (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 construction of these two projects was suspended in April 1981 in view of the large cost overruns experienced by the Sohun (commissioned 1980) and Ru Creek (commissioning April 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 therefore such plants may not be as viable in PNG as in other countries. (For further discussion of rural electrification see Annex T I). Solar Water-Heating 3.40 The Government has underway a highly successful program of conversion from electric to solar hot water heating. A typical installation, imported from Australia to install or retrofit an existing electric hot water installation costs 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 substantial rainy season, back-up electricity water heating is necessary. It is understood that solar heating equipment might be manufactured in 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 regulations which effectively banned installation of electric hot water heaters in new homes and buildings and provided tax write-off incentives to retrofit existing electric installations. The 7,000 solar installations will 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 coincidence factor is the fraction of all electric water heaters in the system that would be switched on simultaneously at any one time.  - 41 - heaters in the system and realizing that most locations would require boosters for the rainy season. Photo-Voltaic Cells (PVC) 3.42 PVC can be used to provide light or refrigeration or to run water pumps and fans. At the high cost of K 550 (US$825) for a two light installation in 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 telecommunication equipment or refrigeration of medical supplies in isolated areas. Its broader use for rural electrification is unlikely to develop not only because of cost, but also because in most rural households even 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 applications may become more attractive. For this reason the relatively low level of funding on these projects may continue. Wind-Electric Generation 3.43 Wind in PNG is comparatively localized. Moreover, wind generation is 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 eventually make a substantial impact 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 discovered gas 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 requirements for such industries located in PNG. Another option that is being considered is the development of a large hydro based aluminum smelter (although this 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 electricity options available are handicapped by small scale and consequent high costs, but the development of large enclave hydro-based industries 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 materialize in eight years, partly because market prospects for aluminum look poor in the near future, while the hydro scheme necessary for a metallurgical industry would have a substantial lead time. No new enclave minerals projects are included in the forecast, and so the structure of the economy is assumed essentially unchanged on the demand side. Electricity 4.03 Forty percent of all petroleum imports are used for power generation, for which there are many substitution options available. Table 4.1 summarizes the forecasts for electricity generation by BCL, Ok Tedi, the public utility network (ELCOM) and small captive generation. 1/ Several aluminum companies, including American and Japanese companies, have shown interest in utilizing these resources.  - 43 - Table 4.1 Forecast of Electricity Generation, 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 generating electricity: hydro, indigenous gas, imported oil, and imported coal. Given the Ienclave type of development typical 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 feasibility studies 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 scenarios have been worked out for 1990. For 1985, there are no alternative scenarios due to the short lead time available although 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 electricity in 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 condensates from Pasca will be recovered and exported. Hydro will be developed at BCL, in addition to the coal- fired thermal station mentioned above. Investment costs 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 recommended by consultants to BCL (para. 2.13).  - 44 - 3. Case C (Business as Usual) (BAU): Dependence on fuel oil and distillates for a substantial part of thermal.generation continues, and a run-of-river hydro 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 electricity generation 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 Electricity Generation 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 corresponding fuel inputs required for the different scenarios is shown in Table 4.3.  - 45 - Table 4.3 Fuel Inputs Required For Electricity Generation ( 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 consumption of 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 expatriates working in the country. In the second half of the decade gasoline consumption is forecast to grow at 3% per annum and distillates at 5% per annum. These rates are slightly higher than those achieved in the past decade, but in that decade real prices rose 100% and GNP stagnated. In the 1980's further substantial real 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 consumption is projected to grow at 5% per annum while Avgas remains constant. Industry 4.08 During the 1980's, BCL is projected to handle 4% more ore 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 consumption of distillates of 51,100 tonnes. Ok Tedi will have reached Stage III by 1990 and is assumed to consume 21,200 tonnes of distillate in mining and processing ore, and 7,000 tones of fuel oil in copper concentrate drying. Agricultural processing is assumed to continue substituting biomass for oil, thus reducing its  - 46 - demand for distillates to 4,000 tonnes while biomass demand rises by 3% per annum to 88,000 TOE. Remaining industrial fuel use is assumed to grow at 7% but its composition depends on the relative prices of alternative fuels. If gas and condensates are available in Port Moresby there will be some substitution of gas for other fuels. Other Sectors (Agriculture, Households, etc.) 4.09 Tractor demand for distillate is assumed to rise at 3% per annum reaching 5,200 tonnes by 1990 for the agricultural sector. Kerosene consumption in the household sector is assumed to grow at 5% per annum to 28,000 tonnes by 1990. Urbanization is expected to continue at past rates. Per capita woodfuel consumption is 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 calculations have been made to show the effect of methanol production on the import bill (Table 4.7). Annex I, Table I.9 corresponds to the coal option while Annex I, Table I.10 reflects the Business-as-Usual scenario. Table 4.4 below shows forecast final energy consumption pattern for 1985 and 1990 1/. 1/ Annex I, Table 1.11 shows final energy consumption without copper (BCL and Ok Tedi) and exports.  - 47 - Table 4.4 Forecast Final Energy Consumption Pattern for 1985 and 1990 (in -000 TOE) Electricity Petroleum Woodfuel Total 1985 Households 12 22 430 464 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 generation already included in electricity. 3/ Historical growth rates in total energy consumption during 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 condensed energy balances appear in Annexes I (Tables I.7, I.9 and I.10) corresponding to 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 Commercial Energy Required 1305 1285 1274 Less Transformation Losses (generation and other losses) -570 -550 -539 Total Final Commercial Energy 735 735 735 Non-Commercial Energy 561 561 561 Total Final Energy 1296 1296 1296 1/ Annex I (Table I.8) also shows Case A (Gas) in detail with the production and export of methanol. 4.12 Energy inputs will be higher than the final energy consumption shown in Table 4.4 by the transformation and transmission losses 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 Transformation losses 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 substitutes for 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-oriented petrochemical industry such as methanol. Rough calculations suggest 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-$381 million, 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 currently high share of export revenue (24% in 1980) eroding the increased revenues from mining. In Case A (Gas) with exports of condensates and methanol, the deficit on energy trade falls to $82 million (assuming methanol exports equivalent to US$137 million) or 5% of projected export earnings which is below its share in 1969-70. 4.16 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. 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 INSTITUTIONS AND 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 responsible for technical advice on all exploration matters 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 hydroelectric sites, the National Weather Service and the Division of Mines, which is responsible for the implementation of the Petroleum Act, issuing of licences, monitoring of safety and the organization of the Petroleum Advisory Board (PAB). These four divisions are under the overall supervision of the Policy and Planning Division, which has responsibility for coordination of negotiations over oil and gas concessions and formulation of 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 organizational chart of the DME as of November 1981 is shown in Annex VI. 5.02 In addition, a forum for interaction and exchange of information among the various parts of government on developments in the energy sector is provided by the National Energy Planning Council (NEPC). This was designed to be an interdepartmental group, with no executive powers, headed by the Minister of DME and representatives of the following: Department of Primary Industry, Office of Forests, National Planning Office, Department of Finance, ELCOM, Department of Works and Supply, Office of Village Development and Office of Environment and- Conservation. The Energy Planning Unit (EPU), which also reports to the Policy and Planning Division, acts as the Secretariat for 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 exploration for minerals and petroleum. With regard to the latter, it is responsible for the collection and review of past exploration data from oil companies and 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 expatriates and six PNG nationals, all exploration geologists and geophysicists, look after both minerals and petroleum. Because of the importance of oil and gas for PNG, and considering the need for early utilization of already firmed-up gas reserves and the possibility of  - 52 - finding oil, it is recommeded that the existing group in the Geological Survey Division be strengthened by hiring highly specialized petroleum experts 1/. At a later stage consideration may be given to the establishment of 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 negotiation of contracts with oil companies as well as monitoring of contracts, duties now shared by the Geological Survey and the Division of Mines. 5.04 The Geological Survey Division also handles geothermal exploration and has a volcanological observatory, based in Rabaul which maintains seismic and geomagnetic monitoring stations throughout PNG. Only limited work has been done by the Geological Survey Division to establish the geothermal potential. The same also applies to the coal sector. Although there have been reports of occurrences of coal and lignite, especially in the Gulf Province, in the Central Highlands and New Britain and New Ireland, the DME has not promoted adequate exploratory work to establish reserves. This again might be an indication of the many varied responsibilities of the Geological Survey Division and the need for strengthening it in the area of coal exploration. The Energy Planning Unit 5.05 The Energy Planning Unit was established at the end of 1978 within the Department of Minerals and Energy for the purpose of formulating energy planning and policies. Its staff has increased from 2 at the end of 1980 to eleven professionals, mainly expatriates, with its main expertise in the renewable forms of energy. The Government issued 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 technical or 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, particularly those dealing with ethanol, seem to have been initiated without adequate data, and a cost reappraisal of these projects has already led to some of them being abandoned. The availability of a tremendous biomass resource makes it a natural target for development in an energy hungry country like PNG. However, inappropriate technologies seem to have been chosen for some of the utilization of biomass with the result that substitution of oil by biomass in industry, other than agricultural processing, has not taken place to any significant extent. 5.06 In view of the importance of energy planning in PNG, with its 1/ This is now being contemplated as a component of the second phase of the petroleum exploration project 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 ELCOM is 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 ELCOM has operated with three departments (commercial, management, engineering) and several divisions and sub-divisions (electrical, generation, transmission/distribution, finance, administration, supplies and more recently, 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 ELCOM to 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, ELCOM reversed 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-ELCOM common 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 ELCOM from 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 ELCOM staff.  - 55 - them they have extensive experience in moderate sized utility administration and 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 responsible for the collection of all hydrological data relating to streams and rivers, and evaluation of potential hydroelectric sites. The interaction between BWR and ELCOM in the past has been inadequate and could have resulted in sub- obtimal planning of hydroelectric generation. As the major energy resource of PNG is its vast hydroelectric potential, the misison has recommended: (a) an inventory of all large (50 MW plus) hydro sites, so that preliminary feasibility studies can be made for 3-4 of these sites for potential development of 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 interaction between BWR and ELCOM be strengthened in the selection and planning of all future hydropower stations, with BWR identifying potential hydropower sites and ELCOM determining the 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 exploration and coal prospecting) under the three scenarios outlined in para.4.04 up 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 discoveries and these investments are therefore not included in 6.1. A very preliminary cost estimate of US$240 million for Pasca field development with recovery of condensates and gas pipeline to Port Moresby is, however, included. 6.04 Besides the development of the gas fields, the other major investment would 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--use of 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 development of new hydro with a storage dam. Investment figures for BCL therefore vary from US$50 million to US$280 million. ELCOM investments are estimated at US$157 million to US$210 million over the next 8 years. Table 6.1 gives an idea of investment forecasts for the energy sector up to 1990. These figures are largely illustrative, given the considerable differences between the various scenarios and the lack of reliable cost estimates.  - 57 - Table 6.1 Investment in the Energy Sector 1981-1990 1/ (Million US Dollars) Case A Case B Case C (Gas) (Coal) (BAU) ELCOM Investment to 1985 2/ 140.0 140.0 140.0 Other investment 15.0 15.0 15.0 Port Moresby electricity 12.0 43.5 67.5 Gas Field development 150.0 - - Gas Pipelines to 'Port Moresby 90.0 - - BCL - hydro 150.0 - - BCL - coal 132.0 200.0 49.4 Ok Tedi diesel 18.0 18.0 18.0 Ok Tedi hydro 150.0 150.0 150.0 Total 4/ 857.0 3/ 565.0 440.0 1/ The estimates for hydro investments are based on figures from CT Main for a variety of hydro projects, most of which have capital costs (in US$ 1980) in the range $1500-2500/kw capacity for run-of-river. Diesel costs are assumed to be $800/kw, coal between $1350-1500/kw depending on scale, and oil fired thermal $1000-1125/kw. The coal and oil figures are 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 investment in a methanol plant estimated at $300 million. 4/ Does not include investment in 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 expenditure of oil and gas ($30-$40m per annum) and investment in a gas based export oriented petrochemical plant 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 comparisons ignore other costs, but help place the investment levels in perspective. The cost/benefit ratios 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 Forecasting Methodology 1970, 1975, 1979 and 1980 Balances (Tables I.1 - I.5) 1. The first step was to construct energy balance for "1970", "1975" (actually averages of fiscal years 1969/70 and 1970/71, 1974/75 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 electricity production and use, and EPU data in woodfuel consumption. Industrial fuel use was based on Newcombe's survey 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 historical data). Energy Balance 1985 (Table 1.6) 2. Forecasts for fuel consumption for 1985 and 1990 were then based on estimates of sectoral growth rates, fuel substitution possibilities, and likely developments in each sector as set out in Chapter 4. For example, BCL's projection of power demand, and Ok Tedi's development plan were used to project fuel demands by the mining enclave, while the gradual substitution of biomass for oil in the agricultural processing 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 development of the economy can be better appreciated by 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 Total 7 8 9 IEA Motor Petroleum Total Non- Total Row 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 54 112 112 112 :'2 Air 17 31 48 48 48 23 Coastal 11 ll 11 11 24 ot:her Sectors 25 Agc. 3 3 3 3 25 Commerce 1 1 1 2 2 27 I;ub.Service 1 1 1 28 Domestic Rulral 4 4 4 307 311 Urbari s 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 7 28 Domestic 1 5 5 1'ural 8 8 8 356 364 Urban 1 10 10 * .9 20 22 3 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. Total. IFA COL. NO. 3 4a 4b 4c 4d 4e 4f Petroleum 7 8 91 POW Motor Residual Products Total Non- Total Co: NO. __ _ LPG Avgas Gasoline Avtur Kerosene Distillate Futel Oil CL L - ydro /i -eticiryC Cola.3-9 Coa-eci a oa 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 & Loss sN 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 Calculated equivalent power plant input assuming 28% efficiency or 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 ~~~~~~112 1901 I'aolftlWtf 304 112 1902 302 304 606 561 1167 r ;,; a s 304. 7 .120 66 29 339 12 573 877 877 31 77 - -18 !-.178 1 --178 f.t~n 1:vSy R.q. _ 304 112 12 7 120 66 29 339 12 join m5 i l< .... f ,,eratf-)n ........ 8 -304 -997 -72 -7 2 -475 -304 218 -561 -561 - ~~~ ~~~~ ~~-9 -9 -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 80 138 218 218 13 8 1 9529 42 34 76 88 .164 is., -.~ 120 146 266 266 266 266 Ai, ~ ~ ~~~~~~~~~7 66 73 73 73 '73 v 2.' I 22 28 28 28 Ai-. S: 5.r Agl. 5 ! 5 5 5 6 C.;1 C S,erce .3 3 3 13 1 6 16 2u,tiUc S.erv1ce 1 1 1 7 S a 12 12 12 12 435 447 IIr~~~~~~~~~~~~~~.sn 1 ~~~~~~~~~~~~~~~~~~~15 16 i . 17 33 33 71 L" t "i, isctctc to" of oil eulivJlorkt Is defils,d ae 10 mllliot K cai. 7b C Ics,l-tsd eq.IvalenL pow.ir plant Iniput )a,uIIg %Z efflcj1uncy C/ Calculated at 860 Kcal/kWh. * This Energy Balance corresponds to Case A (Gas) except for the fact that production and exports of niathanol are not included.  ANNEX I TABLE 1. 8 C Page 10 of 13 CONDENSED ENERGY BALAMCE Forecast 1990 (in thousands of metric tonnes oil equivalent) Gas Case: (Offshore gas with ) .__ ___ ___ _ _ Methanol ) Primary Gas 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'nin g 80 80 138 218 . 218 Other 13 29 42 34 76 88 164 Transport 367 367 0 367 367 Other 37 . *37 37 74 473 547  TABLE 1. 9 ANNEX I Page 11 of 13 CONDENSED ENERGY BALANCE Forecast 1990 (In thousands of 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 CONDENSED ENERGY BALMNCE Forecast 1990 (in thousands of metric tonnes oil equivalent) (Business as 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%o of 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-river Ramu hydro station with 45MW installation, dry season reliability output 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 availability since some units are often shut down for repairs. The system comprises a transmission network 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 transmission system has serious impact and necessitates substantial load shedding. 4. The Port Moresby system supplies the city itself and rural environs. Power is transmitted from the Rouna plants at 66KV. originally designed for regulated inflow by the upstream Sirinumu reservoir on the Laloki River, the hydroplants were 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 mismanagement of 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 expenditures on 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 rehabilitate the 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 ~~~~ANNEX II Page 3 of 5 6. Capital investment by ELCOM during the period 1973/74 and 1980 is given in Table II.2 below. TABLE II.2 ELCOM Investment 1973/74 - 1980 O(illion Kina) Construction Expenditure Investment Current Prices (1980 Prices) 1973/74 14.16 24.5 1974/75 17.86 26.7 1975/76 15.19 20.8 1976/77 20.72 26.5 June-Dec. 1977 6.96 8.8 1978 12.96 15.4 1979 13.05 14.6 1980 7.65 7.6 Total 108.6 144.9  - 75 - ANNEX 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 ELCOM domestic 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