Privatization And Regulation In Malaysia

Letters

Privatization and regulation in Malaysia’s power sector Francis Xavier Jacob Electricity Regulation Division, Department of Electricity Supply, 19th floor, Menara Haw Par, Jalan Sultan Ismail, 5068 Kuala Lumpur, Malaysia 1. Overview of the power sector Malaysia has considerable energy resources, in the form of oil, natural gas, hydroelectric potential and coal. It has about 4.4 billion barrels of recoverable reserves of oil. Of the 1.92 trillion standard m3 of natural gas discovered in Malaysia, 325 billion standard m3 is associated gas. The hydroelectric potential in the country is estimated to be about 29,000 MW with an annual energy output of 123

TWh. Malaysia’s coal reserves are about 977 million tonnes. The installed capacity for electricity generation increased at an average annual rate of 9.2% in the 1980s, mainly in the form of oil- and natural gas-powered plants. The average annual growth rate in consumption during this period was 9.1%. The industrial sector accounted for a major share of the growth, and in 1990 it was also the major consumer (46%), followed by the commercial (31%) and residential (20%) sectors respectively. As a result of government emphasis on rural electrification programmes, over 82% of households had access to electricity by 1990. Electricity supply in Malaysia is currently being undertaken by the Tenaga Nasional Berhad (TNB) in peninsular Malaysia, the Sabah Electricity Board (SEB) in the state of Sabah and the Sarawak Electricity Supply Corporation (SESCO) in the state of Sarawak. TNB, which used to be

Figure 1. Malaysia: network of Tenaga Nasional Berhad (TNB).

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a wholly government-owned public utility, was incorporated in 1990 as a private company with the Government of Malaysia owning over 70% of its equity. All three utilities carry out generation, transmission and distribution of electricity in their operating areas. In May 1995, TNB had an installed capacity of about 7,400 MW, which is supplemented with about 2,000 MW of capacity from independent power producers (IPPs) to meet a maximum demand of about 5,900 MW (see Figure 1). In its financial year ending on August 31, 1994, TNB generated 33.984 TWh of electrical energy of which about 42% was from natural gas, 30% from oil, 13% from coal and 15% from hydro. TNB currently serves about 3.53 million consumers (3.0815 million domestic; 429,800 commercial; 11,400 industrial; 11,200 public lighting; and 100 mining). At the beginning of 1994, SESCO had an installed capacity of 524 MW for a maximum demand of about 245 MW. In 1993, it generated about 1,456 GWh of energy of which 56% was from natural gas, 29% from hydro and 15% from oil. SESCO currently serves about 211,700 consumers (177,100 domestic; 32,300 commercial; 500 industrial; and 1,800 public lighting). At the beginning of 1994, SEB’s installed capacity was 454 MW and catered for a maximum demand of about 280 MW. In the 1,540 GWh of energy generated in 1993, the mix of sources was 49% oil, 26% hydro and 25% natural gas. It currently serves about 192,700 customers (161,300 domestic; 27,500 commercial; 3,100 industrial; and 800 public lighting). At present, the tariff structure for TNB, SEB and SESCO ranges from about RM 0.07 to RM 0.46 (1 Malaysian ringgit or RM1 = US$ 0.39), with off-peak industrial use being charged the lowest rate and public lighting the highest. Electricity tariff for sale of energy by the utility to the public has to be approved by the government. The mechanisms for tariff adjustment for Tenaga Nasional Berhad have been put in place on the basis of the formula CPI - M + Y + K where CPI is the consumer price index, M is a factor which takes into account the inefficiency of operation of the utility and its capital investment needs, Y is the fuel cost pass-through and the factors to take into account the purchase of energy from IPPs and K is a correction factor to take into account forecasting errors. The formula has been operationalised since September 1993 and in the first and second reviews of the electricity tariff, reductions of 3.3% and 5% were made. The tariff is to be reviewed every 3 months, to take into account regularly the changes in fuel prices. This tariff mechanism has made prices of electricity more transparent and predictable. 2. Perspective planning The Malaysian Vision 2020 envisages a doubling of its economy every ten years for the next three decades. The Second Outline Perspective Plan 1991-2000 (OPP2), also known as the National Development Policy (NDP), will set the pace for Malaysia to become a fully developed nation by the year 2020 in all respects. The Malaysian Energy for Sustainable Development

economy is targeted to grow at 7% per annum in the decade of OPP2. In view of the targets set under Vision 2020, it is important to ensure that energy does not become a constraint for growth and that this sector develops on a least-cost basis. Recognising this importance of the availability of energy at economically acceptable cost and in sufficient quantity, three key objectives constitute the framework for present and future programmes in the energy sector: 1. a supply objective, to provide adequate and secure energy supplies; 2. a utilisation objective, to promote efficient energy utilisation and to discourage non-productive and wasteful patterns of energy consumption; and 3. an environmental objective, to ensure that, in achieving the previous two objectives, the environment is not neglected. The four-fuel policy identifies four main fuels: oil, gas, hydro, and coal. The strategy is to cut down on the use of oil and to promote the use of non-oil indigenous resources such as gas, hydro, and coal. In this respect, the 1990s will mark the nation’s entry into an era of greater utilisation of natural gas. Apart from being the least-cost option for power generation expansion in the medium term, its development will be the basis for downstream activities in energy-related industries to provide an added catalyst to accelerate industrial growth. On the utilisation side, demand management policies will focus on promoting efficiency in energy use. Appropriate measures will be introduced to eliminate waste. These include incentive tariff schemes and the promotion of efficient end-use equipment and appliances. Efforts are being made to ensure effective and well-coordinated enforcement of environmental protection programmes, apart from the mandatory requirement of conducting environmental impact assessments (EIAs) for all energy projects. Pricing policies will be directed at ensuring that energy prices reflect the economic cost or true cost of supply, that they raise revenues for the sector’s development and that the sector remains competitive while making greater use of indigenous energy resources. With regard to electricity pricing, the availability of electricity in adequate quantity and quality and at reasonable prices is necessary for the promotion of industrial development. Towards this end, efforts will be made to ensure stability in electricity tariffs at acceptable and internationally competitive levels. At the same time, the needs of power utilities to generate sufficient revenues for future development plans will be taken into account. 2.1. Growth forecast Electricity demand projections for the future are pervaded by uncertainty and a variety of scenarios, making it difficult for decision-makers to prepare concrete plans. The challenge is to incorporate these complexities into strategic developments without causing inaction to result. The power sector, as is widely recognised, forms part of and interacts with a more complex system that includes economic, demographic, financial and environmental elements. Population growth, resource endowments, energy l

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Table 1. Projections of maximum demand (MW) for Peninsular Malaysia, Sabah and Sarawak Annual demand in MW Scenario

1990

1995

2000

2010

2020

3477

6444

9912

19087

26796

Sabah

199

352

521

1109

2206

Sarawak

194

357

547

1100

2231

3447

6444

9930

19388

31511

Sabah

199

352

522

1126

2594

Sarawak

194

357

548

1117

2623

3447

6130

8937

15513

25191

Sabah

199

335

470

901

2073

Sarawak

194

339

494

894

2097

3447

6332

9726

18705

34760

Sabah

199

346

512

1087

2861

Sarawak

194

350

537

1078

2894

(a) Low growth (business as usual) Peninsular Malaysia

(b) Moderate growth (business as usual) Peninsular Malaysia

(c) Moderate growth (energy efficient) Peninsular Malaysia

(d) Targeted growth (energy efficient) Peninsular Malaysia

prices, terms of trade, etc., are among the parameters which affect this system directly or indirectly through other systems. Electricity requirements are also affected if energy efficiency measures are adopted. Thus, two scenarios are possible. 1. A business-as-usual (BAU) case without any serious attempts to make the system energy-efficient 2. An energy-efficient (EE) case with greater emphasis on energy efficiency improvements. Energy efficiency gains are assumed to reach 5% in 1995, 10% in 2000 and 20% in 2010 and thereafter. For the purpose of this paper, the electricity requirements are considered for four scenarios. 1. A low-growth, BAU scenario. Here the load is forecast with the economy projected to grow at 5.3% per annum over the three decades to 2020. 2. A moderate-growth, BAU scenario. Here the load is forecast with the economy projected to grow at a rate of 6% per annum over the same period. This is the projection given in the Sixth Malaysia Plan and the Outline Perspective Plan 2 (OPP2). The share of manufacturing in the gross domestic product (GDP) will increase from 27% in 1990 to about 37% in 2000. Manufacturing exports are projected to account for about 81% of the value of total exports in 2000 from 60.4% in 1990, while agricultural exports will decline to 6% from 10% in the same period. 3. A moderate-growth scenario again but with energy efficiency measures in place. 4. A targeted-growth, energy-efficiency scenario. Here 82

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the load is forecast with the economy projected to grow at 7% per annum over the OPP2 period. This is the growth necessary to enable the target of eight-fold increase in GDP to be achieved. A population growth from 18 million in 1990 to 34.7 million in 2020 is assumed. The medium- and targetedgrowth scenarios are assumed to lead to a three-fold and four-fold increase in per capita income respectively. The demand projections for the various scenarios are shown in Table 1. 2.2. Financial requirements Based on the electricity requirements as shown in Table 1, the financial requirements to provide for the generation, transmission, and distribution capacities and other expenditure are as shown in Table 2 for the targeted-growth energy-efficient scenario[1]. 3. Privatization policy With a view to finding new sources to finance the expansion of the energy sector that would be required even under the energy-efficient scenario, the Government of Malaysia has commissioned a number of studies on power sector privatization. Peninsular Power carried out a study on privatization of the National Electricity Board. Subsequently, Price Waterhouse Associates was hired to study and develop and operationalize the regulatory framework for the electricity supply industry in Malaysia. British Columbia Hydro then conducted a study to identify how competition in the electricity supply industry in Malaysia is to be further pursued. All these indicate serious commitment on the part of the government to ensure carefully l

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Table 2. Financial requirements for targeted-growth energy-efficient scenario projects Period

1991-1995

1996-2000

2001-2010

2010-2020

3578

4577

11155

19067

Sabah

288

274

174

0

Sarawak

242

382

2120

6776

4108

5233

13449

25843

Generation expenditure

7.19

10.47

33.62

77.53

Transmission expenditure

3.59

5.23

16.81

38.76

Distribution expenditure

2.88

4.19

13.45

31.01

Other expenditure

0.72

1.05

3.36

7.75

Total expenditure

14.38

20.93

67.25

155.06

New capacity required (MW) Peninsular Malaysia

Total Financial requirements (billion $)

designed and smoothly implemented steps towards privatization of the power sector. In September 1990, the Government of Malaysia enacted the Electricity Supply Act and, with this, started a chain of events towards privatization of the electricity supply industry in Malaysia. First, the National Electricity Board was corporatized as Tenaga Nasional Berhad, or TNB. The corporatized utility was then privatized in February 1992 with the Government of Malaysia owning about 73%. In February 1991, the government released the Privatization Masterplan which details, among other issues, the privatization of ‘‘new projects’’. These ‘‘new projects’’ are projects which traditionally have been developed by the public sector and include electricity supply projects. According to the Sixth Malaysia Plan (1991-1995), ‘‘... private sector participation will be promoted to encourage competition in the (power) sector. Towards this end, the concept of build-operate-transfer, particularly in power generation, will provide avenues for private sector participation.’’ To follow through on its promise, the government decided to introduce competition in the generation field by inviting IPPs to build, own and operate generation plants. The IPPs that have been licensed so far are in the form of locally-led consortiums having foreign members, the ratio of local and foreign shares being generally about 75:25. By 1997, the power generated by IPPs will be over 4000 MW and will account for about over 30% of total generation. At present, IPPs are expected to sell their energy only to the utilities, which will continue their traditional role of generation, transmission and distribution. 3.1. Objectives of privatization The Government has several objectives in privatising the electricity supply industry in Malaysia. The main objective is to relieve the government of the administrative and financial burden of providing electrical power for the country. This will release more funds for other socio-economic projects. In fact, with the already licensed IPPs, power generation investment by the private sector Energy for Sustainable Development

amounted to over RM 10 ($3.9) billion by the end of 1994. Privatization will promote competition and subsequently improve efficiency and productivity in the electricity sector. The improved efficiency is expected in the economic, financial and technical fields and the consumers can expect to receive better and improved services at reasonable prices. Privatization will also stimulate private entrepreneurship and investment. This will accelerate the rate of growth of the economy consistent with Malaysia’s Vision 2020 in which the government envisages the private sector to be the prime engine for growth. The objectives of the New Economic Policy (NEP) are also expected to be met through privatization. This policy, now replaced by the National Development Policy (NDP), has the objective, besides others, of the creation of a local commercial and industrial community. 3.2. Regulatory framework The privatization of the electricity industry places an essential service in the hands of the private sector. Regulatory mechanisms are thus necessary and are already in place. The Electricity Supply Act 1990 provides the legislative framework for the regulation. Two important regulations made under this Act are: 1. Licensee Supply Regulations 1990, and 2. Electricity Regulations 1994. In addition, the Malaysian Grid Code is being introduced as a set of comprehensive technical and operational requirements for all plants connected to the national grid to ensure: 1. safe, secure, reliable and economic electricity supply system, and 2. access to it of all users without discrimination. The licence terms and conditions also forms part of the regulatory framework. 4. The process of becoming an IPP The following is a brief account of the actual approval process for IPPs under the new arrangements. Potential interested parties should first forward their proposals to l

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the government through the Economic Planning Unit (EPU). Once the government gives its approval, the candidate IPP will negotiate the fuel purchase agreement and the power purchase agreement with the relevant parties. Upon successful conclusion of these two agreements, a licence will be issued by the Director General of Electricity Supply after being approved by the Minister of Energy, Telecommunication and Posts. The licence is normally for a period of 21 years. All the IPPs to date have agreements based on the build, operate and own (BOO) model. 4.1. Players involved in approval process Apart from the Department of Electricity Supply and the Ministry of Energy, Telecommunications and Posts, under which the former operates, the Economic Planning Unit of the Prime Minister’s Department, the Treasury and the Department of Environment are also involved in the approval process of IPPs. Of the five major IPPs at present, only the project of Segari Power Sdn Bhd has foreign participation. Here Asea Brown Boveri Holdings Sdn Bhd has 25% equity in the project. At present there are no tax breaks or concessions given to the IPPs. Some of the other players involved in IPPs include: l project contractors; l plant equipment suppliers; l fuel suppliers (for most of the IPPs, Petronas supplies the natural gas); l operating and maintenance contractors; l operating and maintenance spares suppliers; l financiers and those who arrange the financing packages; l insurers; l providers of freight services; and l legal and technical consultants. 4.2. Power purchase agreement (PPA) The following are the salient features of the PPA between TNB and one of the IPPs. l Sale and purchase obligations Sale and purchase of electric energy: The IPP shall deliver and TNB shall purchase and accept the net electrical output from each unit as such unit is dispatched by the Control Centre. Sale and purchase of generating capacity: The IPP shall make available and TNB shall pay for the dependable capacity of each unit up to but not exceeding the site rating of the unit. During system emergencies the IPP shall, at TNB’s request and subject to provisions of the Grid Code, make all reasonable efforts to provide electric energy or generating capacity above the dependable capacity of each unit then in effect and shall, at TNB’s request, make all reasonable efforts to delay any relevant scheduled outages, maintenance outages and major outages. This should be done consistent with design limits and prudent utility practices. l Purchase price and other charges 4.3. Capacity payment This will be done in accordance with the following formula: 84

Energy for Sustainable Development

CP=DC × (CRF + FOR) × F × (AF/AT) where CP = Capacity payment in ringgit for such capacity billing period DC = Average of the dependable capacity (net) of the facility for such capacity billing period in kilowatts weighted by the number of hours attributed to each period of differing dependable capacity of the facility in such capacity billing period CRF =Capacity rate financial for such capacity billing period in RM/kW/month. FOR =Fixed operating rate for such capacity billing period in RM/kW/month. This will be adjusted every 4 years by an adjustment factor based, among other things, on the consumer price index for Peninsular Malaysia. F = The factor set at 1.0 if AF is greater than or equal to 80%, at 0.95 if AF is greater than or equal to 65% but less than 80%, at 0.9 if AF is greater than or equal to 50% but less than 65% and at AF/AT if AF is less than 50%. AF = For each capacity billing period, AF equals the arithmetic average of the monthly equivalent availability factor for the previous 12 capacity billing periods (including such capacity billing period), expressed as a percentage. AT = The availability target set (1) at 87% if AF is less than 87%, and (2) equal to AF for values of AF equal to or greater than 87%, except that, for each capacity billing period for which AF is greater than 94%, the availability target is set at 93% if (a) the monthly equivalent availability factor for each of the previous six capacity billing periods is also greater than 94%, and (b) for each such capacity billing period and the previous six capacity billing periods, DCU for each unit is not less than 92.7% of the plant nameplate capacity, and (c) such capacity billing period is occurring at least 12 months after the commercial operations date for the unit. As used herein, ‘‘DCU’’ means, for each unit, the average of the dependable capacity of such unit for such capacity billing period in kilowatts weighted by the number of hours attributed to each period of differing dependable capacity of such unit in such capacity billing period. 4.4. Energy payments This will be done in accordance with the following formula EP = (E × H × NEO) / 1,000,000 + VOR × NEO + S where EP = Energy payment in ringgit E = Weighted average cost of fuel (in RM/MMBTU) paid by the IPP under the fuel supply contracts and used at the facility during such energy billing period, calculated by dividing the aggregate amount (in RM) paid by the IPP for such fuel by the aggregate MMBTU of such fuel. For purposes of the preceding sentence, ‘‘fuel’’ means (1) during any distillate period occurring (a) prior to the start-up l

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date and (b) after natural gas is first available to the facility, distillate fuel oil, and (2) at any other time (whether natural gas or alternative fuel is being used), natural gas. The IPP shall provide TNB with a written statement showing the method of calculation thereof, together with supporting documentation, including copies of all statements under the fuel supply contracts, within three days after the end of each energy billing period. If any alternative fuel is consumed by the facility at any time during such energy billing period when natural gas is available, such alternative fuel shall, for purposes of calculating E, be deemed to be natural gas consumed in a quantity having (1) the same BTU content as the BTU content of the alternative fuel actually consumed and (2) a price (in RM/MMBTU) equal to the average price for natural gas under the fuel supply contracts for such energy billing period. H = Assumed net heat rate (in BTU/kWh) set at 12,108 BTU/kWh based on (1) higher calorific value of natural gas at assumed conditions, and (2) the relevant unit operating at a continuous load of 100% of the net generating capacity of such unit available for dispatch by TNB. For purposes of calculating the energy payment for any energy billing period, such net heat rate shall be adjusted (in accordance with the heat rate adjustment table set forth in given exhibit) to reflect any dispatch by TNB at part load operations (determined as a percentage of the net generating capacity of the relevant unit available for dispatch by TNB) during such energy billing period. NEO = Net electrical output (in kWh) of all units for such energy billing period. VOR = Variable operating rate for such energy billing period in sen/kWh. This will be adjusted every 4 years by an adjustment factor based, among other things, on the producer price index for Peninsular Malaysia. S = The quotient obtained from dividing (1) the product of (a) the number of start-ups requested by TNB during such billing period (excluding any additional start-ups caused by the IPP or the facility, e.g., tripping or outage of the facility, or failure of the facility to start up after a start-up request by TNB), (b) 15.4 MMBTU/start-up, and (c) E (as determined above) by (2) 1,000,000. l Compensation, billing and payment l Liquidated damages and maintenance reserve l Pre-operation period l Operation and maintenance -- Operation and maintenance of facility -- Dependable capacity; testing of capacity rating -- Schedule and despatch of generation -- Schedule outages, major overhaul outages and maintenance outages -- Access to facility and site -- Operation committee Energy for Sustainable Development

Interconnection Metering l Representation and warranties l Taxes; fines l Insurance l Force majeure event l Default and termination l Indemnification and liability l Dispute resolution 4.5. Risk factors The PPA requires the following of the IPP. 1. The IPP shall have provided to TNB evidence demonstrating that the IPP has obtained all applicable governmental authorizations, including the IPP licence, other than (1) any governmental authorizations that could not materially affect the ability of the IPP to perform its obligations under this agreement, the fuel supply contracts or the EPC contracts, or (2) any such other governmental authorizations that (a) are not necessary for the IPP to commence generation of electric energy from the facility and (b) the IPP could not reasonably be expected to have obtained prior to the initial operations date given the practice and procedures of the relevant governmental entities issuing such respective governmental authorizations. 2. Each of the fuel supply contracts shall have been executed and delivered by each of the respective parties thereto, and the form and substance of each provision thereof which could reasonably be expected to have a material effect on the ability of the IPP to perform its obligations, or the rights of TNB, under this agreement shall be reasonably satisfactory to TNB. 3. The interconnection facilities shall have been designed, engineered, manufactured, supplied, constructed, installed, tested and commissioned in accordance with the requirements of this agreement and prudent utility practices and shall be able to operate safely with the TNB system. 4. The fuel facilities shall have been designed, engineered, constructed and installed, tested and commissioned in accordance with the requirements of this agreement and prudent utility practices to enable the facility to receive, replenish and utilize supplies of distillate fuel oil under the fuel supply contracts in quantities sufficient to permit the facility to operate continuously at full load dispatch. 5. The IPP shall have provided to TNB a certificate from the independent engineer stating that the facility has been designed and constructed in accordance with prudent utility practices, the design drawings submitted to TNB. The above provisions thus reflect the responsibilities and the risks borne by the IPP in terms of the offtake, completion, operation, fuel, transport, environment and other laws or regulations which may affect its operations. However, the IPP can transfer some of these risks to the parties with whom it enters into contracts for these requirements. For example, it can transfer the risk completion and start-up dates to the l l

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project contractor, the fuel risks to the fuel supplier, etc. For risks it has to bear itself, it may mitigate the risks by takinginsurances. 4.6. Insurance The PPA requires the IPP to have coverage for the following: l comprehensive general liability or third party liability insurance; l workers’ comprehensive insurance; l comprehensive automobile liability or motor vehicle liability insurance; l contractor’s all risks insurance and boiler and machinery insurance; and l excess umbrella liability of excess layer liability insurance. 4.7. Future laws The PPA has a change-in-law adjustment clause as follows: 1. If there is a change-in-law which requires the IPP to make capital improvements or other modifications to the facility in order to comply with any law, the IPP shall submit to TNB a certificate setting forth in detail reasonably satisfactory to TNB the actual costs of such capital improvements and the calculations for such amount. The IPP and TNB shall determine, in good faith, any necessary adjustments to the capacity rate financial to reflect such costs. After the receipt by TNB of the written approval of the Department of Electricity Supply of (1) the amount of such costs and (2) such adjustments to the capacity rate financial, the capacity rate financial shall be adjusted in the manner so approved by the Department of Electricity Supply. 2. If there is a change-in-law (other than in respect of taxes) which the IPP or TNB believes in good faith will (1) increase the costs or decrease the revenues of the IPP in connection with the operation or maintenance of the facility, or other conditions affecting the performance by the IPP of its obligations under this agreement or affecting the timing of the incurring of such costs or the receipt of such revenues, or (2) decrease the costs or increase the revenues of the IPP in connection with the operation or maintenance of the facility, then the IPP (in case of such increase in costs or decrease in revenues) or TNB (in case of such decrease in costs or increase in revenues) shall (a) determine the amount of such increase or decrease in costs or revenues, (b) submit to the other party a certificate setting forth in detail reasonably satisfactory to such party the basis of and the calculations for such amount, and (c) jointly with the other party, determine the applicable adjustments to the fixed operating rate and the variable operating rate to reflect such increases or decreases in costs or revenues with the intent that the financial position of the IPP shall remain unaffected by such change-in-law. Each party shall in good faith cooperate with the other party in connection with such determinations. The fixed operating rate and the variable operating rate (if applicable) shall be adjusted in the manner so determined jointly by the parties. 86

Energy for Sustainable Development

Notwithstanding the foregoing, in case of any such adjustments to the fixed operating rate and the variable operating rate (if applicable) to reflect any such increase in costs or decrease in revenues of the IPP, (1) such adjustments shall not be made until after the receipt by TNB of the written approval of the Department of Electricity Supply of (a) the amount of such increase in costs or decrease in revenues of the IPP, and (b) such adjustments to the fixed operating rate and the variable operating rate (if applicable) so determined by the parties. 4.8. Finance The private power projects are generally financed through single financing. The financial structure involves debt of the private power projects with part of it as a bond issue at a fixed interest rate and the remaining as floating rate loan facility. The equity continues to be owned by the IPPs, who bear the entire development expense themselves. At 4000 MW, the 5 private power projects constitute the largest exercise anywhere in Asia. It is also Malaysia’s largest debt financial package at a total of RM10 ($3.9) billion. All this is financed locally, relieving the 5 IPPs of foreign exchange risks. 4.9. Market for the power produced Only one of the IPPs has a minimum take-or-pay provision. The rest of the IPPs will sell their energy as despatched by the National Load Despatch Centre. Recently one of the IPPs has expressed interest in selling electricity to Singapore and a potential IPP has expressed interest in selling electricity to Thailand. 4.10. Policies and laws on energy and environment The Environmental Quality Act 1974 provides the legislative framework for regulation and policies with regard to the environment. The following are some of the sections of the Act that will have an effect on electric power plants. Section 21: Power to specify conditions of discharge Section 22: Restrictions on pollution of the atmosphere Section 23: Restrictions on noise pollution Section 24: Restrictions on pollution of the soil Section 25: Restrictions on pollution in inland waters Section 27: Prohibition of discharge of oil into Malaysian waters Section 32: Need to maintain and operate equipment Section 34A: Report on impact on environment resulting from prescribed activities One of the conditions in the PPA is for the IPP to obtain all government authorizations. Thus, only after the EIA has been approved by the Department of Environment will the licence to operate the power plant be given by the Department of Electricity Supply. As such, it can be assumed that the IPP will meet the requirement of the environmental laws and regulations and the conditions imposed by the Department of Environment. 5. The impact of privatization in the electricity supply industry The privatization of TNB has been successful. The Government of Malaysia is now less burdened with l

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capital-intensive generation programmes to ensure the country’s economic development. By 1997 Malaysia will have a comfortable margin in generation capacity of 30% as planned and this will ensure security and availability of supply. The response of the private sector to this privatization programme of the government has been very encouraging. This can be seen from the fact that more than 100 proposals have been received from potential IPPs. The knowledge and expertise in the electricity sector is becoming more widespread now. Whereas previously this was concentrated in the 3 utilities, it has at present spread out to other parties. Apart from IPPs, consultants, banks, legal firms, different government agencies and consumers are now becoming increasingly aware of the varied issues involved in the electricity sector. For consumers, the awareness has resulted in their being more critical and demanding with respect to services provided to them. This is evident from the increasing number of complaints received by the Department of Electricity Supply on matters which they had passively endured earlier. While this puts pressure on the utilities, it certainly pushes them to upgrade their services. The breaking-up of the monopolistic situation in the industry and the ensuing competition has motivated those involved in the industry to improve themselves. TNB itself has been forced to improve its performance. One such example is the establishment of a list of performance indicators, thus setting a minimum level of performance the customers can expect of them. This list includes, besides other things, the maximum time-period for connection of new and disconnected supplies, for responding to complaints, the minimum period of notice for planned outages, and the method of collecting deposits. Confidence is being generated that this will result in a better and more efficient industry as a whole. Industry in general is becoming more efficient and the business of electricity provision, in particular, more transparent. This is evident in the way factories having cogeneration potential are now beginning to avail themselves of that facility. Where formerly they would just have to purchase all their electrical energy requirements from TNB and discard waste fuel and/or waste heat, they are now considering seriously the economics of cogeneration. Also, whereas earlier, decisions were taken without reasons being made public, the electricity supply industry is becoming far more proactive. Thus, the utility now provides details of how connection charges are calculated, so that the consumers know what they are paying for. The utility has responded to the situation well by coming up with better and more services. Besides the introduction of incentive schemes for users related to demand-side management, TNB has now started advising consumers on how to improve the efficiency of their electrical equipment and to cut losses. This benefits TNB as

Energy for Sustainable Development

well as the consumers. 6. Salient issues in promotion and implementation of IPPs Various challenges have to be faced as the privatization of the Malaysian electricity supply industry is being undertaken. First of all there are very few examples or models to follow. The advantages and disadvantages of the various models of privatization have to be studied carefully and suitably modified to apply in this country. In this respect, the introduction of IPPs is actually more an exercise in financial engineering than anything else. Each project needs to be analysed carefully in terms of whether it can be financed, long before it can be implemented and operated. While the entire debt funding of the existing IPP projects worth 4000 MW was raised locally, over the next 30 years about 30,000 MW of capacity is needed. To implement such a huge programme, capital investments of the order of RM 100 ($39.2) billion are required. The question is not only the affordability of finance, but also the availability of the funds. The scramble for scarce funds has, in fact, become a global issue and is likely to become a major challenge for the electricity industry. The regulatory framework and the various regulations and codes have to be set up to ensure that the various parties involved in the industry work in harmony with each other and in an efficient and reliable manner. The major portion of this framework is already in place and various other regulations and the Grid Code are being formulated. The sourcing of the fuel necessary for the power sector is another challenge by itself. While oil has traditionally played a major role in this respect, natural gas is increasingly playing a more prominent role. Newer and better technologies in the use of natural gas for generation are available. Notwithstanding this, the fuel diversification policy has to be maintained and achieved to improve the security of energy availability and to reduce the vulnerability of depending on only one fuel source or a group of fuel sources. In this respect, the Government of Malaysia fully realizes the limits to the availability of gas in the future. With this, other sources such as hydro and coal may play greater roles in the electricity sector beyond the year 2000. 7. Some salient features of recent developments Installed capacity in 1997 had reached 11,646 MW, while generation in the same year was 36,156 GWh. About 14 independent power producers had been issued licences for generation by mid-1998. Suggestions for further reading Environmental Quality Act 1974 (and regulations made under it) Power purchase agreements of IPPs Proposed Malaysian Electricity Masterplan (draft)

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Letters

Appendix 1 Highlights of IPP deals

Sl. No.

Name of IPP

YTL Power Generation Sdn Bhd

Sikap Energy Ventures Sdn Bhd

Genting Sanyen (M) Sdn Bhd

Powertek Sdn Bhd

Port Dickson Power Sdn Bhd

1.

Site

Paka, Terengganu, Pasir Gudang, Johor

Lumit, Perak

Kuala Langat, Selangor

Alor Gajah, Melaka

Tanjung Gemuk, Port Dickson

2.

Capacity

808 MW 404 MW

1303 MW

720 MW

440 MW

440 MW

3.

Type of plant

2 Combined cycle block

Combined cycle

Combined cycle

Open cycle 4×110 MW

Open cycle 4×110 MW

4.

Project cost

RM 3.6 ($1.4) billion

RM 3.6 ($1.4) billion

RM 1.0 ($0.4) billion

RM 719 ($282) million

RM 685 ($269) million

5.

Licence issued

7 April 1993

15 July 1993

10 June 1993

1 December 1993

1 December 1993

6.

Energy purchase agreement with TNB

31 March 1993

16 October 1993

6 January 1994

10 December 1993

10 December 1993

7.

Gas purchase agreement with Petronas

15 March 1993

17 July 1993

Not signed yet

Not signed yet

Not signed yet

8.

Technical consultants

Tenaga Ewbank Preece

SWEC Zainal Sdn Bhd

Lahmeyer International

KTA Tenaga Sdn Bhd

Black & Veatch International of Missouri, USA

9.

Finance

Employees Provident Fund, Bank Bumiputra Malaysia Bhd

Malayan Banking Bhd, Bank Bumiputra Malaysia Bhd

Malayan Banking Bhd

Malayan Banking Bhd

Malayan Banking Bhd

10.

Commercial operating date1st generating unit

31 December 1994

1 July 1996

31 December 1994

15 January 1995

15 January 1995

Last generating unit

1 July 1997

1 July 1997

31 December 1995

1 May 1995

1 May 1995

Shareholders

YTL Corporation Bhd

Sikap Power Sdn.Bhd 75% Asea Brown Boveri Holdings Sdn.Bhd. 25%

Syarikat Genting Bhd.

Cergas Unggul Sdn.Bhd35% Arab Malaysia Dev.Bhd 30% Yayasan Melaka 20% Dato’Dr,Mokhzani Abdul Rahim 8% Lim Ewe Jin 7%

Sime Darby Bhd.40% Malaysian Resources Corp.Bhd. 30% Hypergantic Sdn.Bhd.20% Tenaga Nasional Bhd.10%

11.

Notes 1. These costs (in current terms) are calculated on the basis of the following assumptions: Generation costs=$1.75 million per MW for period 1991-1995 =$2.00 million per MW for period 1996-2000 =$2.50 million per MW for period 2001-2010 =$3.00 million per MW for period 2011-2020 Transmission costs=50% of generation costs Distribution costs=40% of generation costs Other costs (e.g., equipment cost)=10% of generation costs

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Energy for Sustainable Development

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