Report No. 13313-PH Philippines Power Sector Study Structural Framework for the Power Sector November 30, 1994 Industry and Energy Operations Division Country Department I East Asia & Pacific Regional Office _ ~'~ .W -~.w~-- _;~ .1 w -..4-..... _-_ --- -.............. ~~~~~- - , ..~~~~~~~~~- 4. -* 0 9E tw. ' . . ' ; "~~~~~~~~~~~'A 4 '. .. . 4 _.Mocurnent of th -wr Bank t S ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ - . 4 ,- ; . ' . ,.>. l~~~~~~~~~~~ PHILIPPINES POWER SECTOR STUDY STRUCTURAL FRAMEWORK FOR THE POWER SECTOR Table of Contents EXECUlTVE SUbMMARY ........................................ ; 1. Realities and Constraints .. A. Introduction. I B. Current Sector Structure ................................... 2 C. Objective of the Study ................................... 4 D. Current Realities and Derivative Issues . ............................ 5 E. Conclusions . ................................... 11 2. Power Demand and Supply . ................................... 12 A. Introduction ........... ........................ 12 B. Power Demand and Supply to 1998 . .............................. 12 C. From Prescriptive to Strategic Planning ........... ................ 17 D. Power Sector Investment ................................... 18 E. Conclusions and Recommendations . .............................. 26 3. Financial Implications ................. .................. 28 A. Introduction . ................................... 28 B. The National Power Corporation ................................ 28 C. Distribution Company Finances ................................. 36 D. Independent Power Producers ........... ....................... 40 E. Summary of Recommendations ................................. 41 4. Effectiveness of the Private Sector ................................... 43 A. Introduction . .................................... 43 B. Effectiveness of the IPPs .................................... 43 C. Effectiveness of the Distribution Utilities .......... ................. 49 D. Directly Connected Consumers ................................. 51 E. Conclusions and Recommendations . ............................. 52 S. Structural Framework ................. ................... 54 A. Current Framework .................................... 54 B. Privatization of NPC .................................... 56 C. Eventual Structural Framework . ............................... 62 D. Transitional Arrangements ................................... 69 E. Conclusions . .................................... 72 6. Requirements for an Enabling Environment ........... ................. 74 A. Introduction ............................................ 74 B. Policy Aspects ........................................... 74 C. Legal and Regulatory Issues .................................. 75 D. Pricing ............................................... 79 E. Accreditation Issues ....................................... 81 F. Dispatch Issues .......................................... 83 G. Summary of Recommendations ................................. 85 7. Regulatory Lssues ............................................. 88 A. Introduction ............................................ 88 B. Summary of Regulatory Issues ................................. 88 C. Independent Regulatory Fund .................................. 90 D. Regulatory Institution Development .............................. 91 E. Summary of Recommendations ................................. 92 Chbrts: Chart 1 Current Structure ........................................ 55 Chart 2 Restructuring of NPC ...................................... 60 Chart 3 Eventual Structure ........................................ 64 Chart 4 Transitional Structure ...................................... 70 Annexes: Annex 1 Supply and Demand Assumptions Annex 2 Status of Private Sector Power Plants Annex 3 NPC's Power Development Program Annex 4 Status of the Distribution Utilities and Financial Benefits of Consolidation Annex S ERB Institutional Development Annex 6 ERB and DOE Regulatory Powers Annex 7 Transparency of Regulatory Institutions Annex 8 Methods of Forming Consolidated Distribution Entities References: Bacon-Manito Geothermal Power Project (No. 6999-PH, May 31, 1988) Energy Sector Study (No. 7269-PH, September 15, 1988) Rural Electrification Sector Study (No. 8016-PH, November 9, 1989) Rural Electrification Revitalization Project (No. 9810-PH, December 23, 1991) Power Transmission and Rehabilitation Project (No. 10996-PH, June 3, 1993) Leyte-Cebu Geothermal Project (No. 11449-PH, January 6, 1994) Leyte-Luzon Geothermal Project (No. 12568-PH, May 9, 1994) CURRENCY EQUIVALENTS (as of May 31, 1994) Currency Unit = Philippine Peso (P) USS1.00 = i 28.0 P 1,000 = US$35.71 I2 1 = 100 Centavos (Ctvs.) WEIGHTS AND MEASURES GW = Gigawatt (1 million kilowatts) GWh = Gigawatt-hours (1 million kilowatt-hours) kWh = Kilowatt-hours (1,000 watt-hours) Kw = Kilowatt (1,000 watts) MW = Megawatt (1,000 kilowatts) HCDC = High capacity direct current HVDC = High voltage direct current kV = Kilovolt (1,000 volts) km = Kilometer (0.6214 miles) MW = Megawatt MWh = Megawatt-hours (1,000 kilowatt-hours) ABBREVIATIONS AND ACRONYMS ADB = Asian Development Bank BOI = Board of Investments BOO = Build-Operate-Own Programn BOT = Build-Operate-Transfer Program BTO = Build-Transfer-Operate COA = Commission on Audits DOE = Department of Energy DOF = Department of Finance DSM = Demand Side Management EO = Executive Order ERB = Energy Regulatory Board IOD = Investor Owned Distributors IPP = Independent Power Producer MERALCO = Manila Electric Company NEA = National Electrification Administration NEDA = National Economic Development Authority NPC = National Power Corporation OECF = Overseas Economic Development Fund (Japan) PD = Presidential Directive PDP = Power Development Plan (NPC) PNOC = Philippine National Oil Company PPA = Power Purchase Agreement ROL = Rehabilitate Operate Lease ROT = Rehabilitate Operate and Transfer SCADA = System Control and Data Acquisition USAID = United States Agency for International Development I Acknowledgements This report was prepared by a power sector mission that visited the Philippines during November 1 - 20, 1993. The mission included: (a) Jamil Sopher, Senior Financial Analyst/Co-Task Manager (b) Claudio Fernandez, Principal Financial Analyst/Co-Task Manager (c) John Irving, Senior Power Engineer (d) Enrique Crousillat, Energy Economist (e) Anil Malhotra, Energy Adviser (f) Peter Cordukes, Principal Financial Analyst (g) Paul Ballonoff, Regulatory Consultant In addition, the mission wishes to express its sincere thanks to Gary Bond (IFC) and Harry Travis (Editorial Consultant) for the substantial assistance he provided, both before and after the mission. We also wish to extend our thanks to Hamideh Keyhani and Martin Edmonds, for the substantial assistance they provided in producing this report. This report was reviewed and cleared by Vineet Nayyar, Division Chief, and William McCleary, Lead Economist and the Office of the Chief Economist of the EAP Region. The peer reviewers include Rafael Moscote, Darayes Mehta, and Bernard Tennenbaum. The mission wishes to express its gratitude for the excellent cooperation and gracious hospitality afforded by the counterpart agencies: the Department of Energy (DOE); the National Power Corporation (NPC); the National Electrification Administration (NEA); the Energy Regulatory Board (ERB); the National Economic Development Authority (NEDA); the Department of Finance (DOF); and the Energy Regulatory Board (ERB). The mission also gratefully acknowledges the management and staffs of the Manila Electric Company (MERALCO); the Cebu Electric Cooperatives (CEBECO); the Visayas Electric Company (VECO); and the Angeles Electric Company (Angeles), who consulted with the team during field visits in the course of the main field mission and an earlier preparatory mission (August 16-September 3, 1993). I PHILIPPINES POWER SECrOR STUDY STRVCTUAL FRAMEWORK FOR THE POWER SECTOR EXECUTTIVE SUMMARY A. Introduction 1. The Status of Private Power Development. Since the Bank's 1988 Energy Sector Study, the Philippines has experienced a major crisis of electricity supply. At the lowest point of the crisis in 1992-1993, brownouts averaging seven hours per day were common in many regions across the Philippines. Facing serious economic losses, the Government sought to supplement the capacity of the National Power Corporation (NPC), the Philippines' monopoly supplier of electricity, with private power development. When the first Independent Power Producer (IPP) delivered a timely addition to generation capacity, the Government came to view a public/private partnership in the power sector as a viable strategy to help curtail temporary capacity shortages. As the shortage crisis deepened, the Government accelerated privatization of the power sector by taking a number of bold steps. It (i) rewrote exclusionary laws, (ii) drafted new policies in support of IPPs, (iii) streamlined clearance processes, (iv) restructured the Government energy sector policy departments and regulatory agencies and, (v) in general, acted to remove the constraints to broader participation of IPPs in Build-Operate-Transfer (BOT) and similar arrangements. By mid-1994, within an improved enabling environment, the private sector had some 30 generation projects under development, accounting for approximately 3000 MW of new capacity. While NPC remains the monopoly supplier for both generation and transmission to all electric distributors, the growing involvement of IPPs will result in a marked transformation of the power generation subsector from nearly 100% public in 1991, to nearly 80% private by 1998. With some 15 investor-owned utilities (lODs) and about 120 member-owned cooperatives (coops) owning and operating the entire distribution system, private interests will have come to predominate the Philippine power sector. 2. Objective of the Study. The devolution of power development to the private sector is a rapidly evolving trend, with important implications for the realignment of public and private sector roles, responsibilities and interests. Because of the urgent need to resolve the supply crisis, the Government has concentrated on creating a favorable climate for private sector-led growth. However, to assure consumers that their power needs will be met, the Government must have the capacity to make sound energy policy and coordinate sector development in the national interest. To this end, the main objective of this Study is to assist the Government to identify an appropriate structural framework to meet long-term energy goals, and to make recommendations on the actions required to guide the transformation to the post-privatization period. - ii - B. Current Sector Structure 3. Private Sector Effectiveness. The recent Philippine private power development experience is marked by a successful supply response to urgent capacity shortages. Installation of 1300 MW by end-1993, completion of about 15 plants by end-1994 and agreements reached for an additional 5000 MW strongly support the policy shift from public to a public/private sector collaboration for the development and rehabilitation of generation capacity. Even with their relatively high costs, the early IPPs were justified in economic terms within a context of extreme supply shortages. More recent IPPs have lower prices and costs closer to international levels, due, among other factors to improved competition. The effectiveness of privatized generation is fully analyzed in this Report. 4. Private Power Financing for Generation. Detailed information on the sources and structure of private financing for power generation is limited. Evidence suggests, nonetheless, that mobilization of load capital for IPPs is on the rise. Moreover, the pattern of debt appears to have shifted from a heavy reliance on official financing in early projects to a growing participation of commercial banks and bond issues in more recent generation investments. Domestic resources have also begun to be mobilized, a phenomenon that warrants support and encouragement. 5. Private Sector Performance in Distribution. Responsibility for distribution in the Philippines lies entirely with some 135 investor-owned private utilities (lODs) or member-owned cooperatives (coops), all of whom have exclusive rights to provide medium and low voltage service within their franchise areas and are subject to price regulation. Only the Manila Electric Company (MERALCO) is of substantial size, with established international commercial credit. The remainder are modest operations serving small towns, villages and rural areas, with a record of operational performance ranging from acceptable to poor. MERALCO is a sound company, capable of self- financing a significant portion of its ongoing network rehabilitation and attracting IPP interest. At the same time, its regular tariffs are distorted by cross-subsidy requirements. The other 14 IODs have demonstrated mixed financial performance, notwithstanding large wholesale-retail markups on NPC- sourced power. They do not own or control their sub-transmission networks, since they lack adequate maintenance capacity. The 120 coops, on average smaller than the lODs, have even less opportunity to become commercially viable, given their size, modest engineering and maintenance capacity and concentration of low-income, low consumption customers. Notwithstanding these constraints, some coops outperform nearby or comparable IODs. 6. Public Sector Effectiveness. As the capacity shortage became a crisis, the Government initiated some restructuring of the various energy agencies, while seeking broader private sector participation. This Study found that the organizational framework of the Department of Energy (DOE), the Energy Regulatory Board (ERB) and the National Electrification Administration (NEA), is sound. Institutional weaknesses, which have been identified, can be remedied through capacity building, training, and a rmalignment of staffing levels with responsibilities. At the same time, however, these institutions do not have the authority or means to adjust their staffing and budgetary resources to address these constraints. Moreover, although the regulatory framework and law are well established, power sector reform will continue to pressure ERB's regulatory capabilities, requiring increased staffing in some instances and improved skills of existing staff. lmportant challenges for the regulators include: (1) the rapid increase of IPP involvement; (ii) legally mandated shifts in organizational responsibilities among the agencies; and (iii) freer interaction in the future between suppliers and consolidated distributors. As the role of private developers increases, - iii - so, too, will the importance of regulation. These challenges can only be met successfully if the Government is committed to addressing the existing capacity constraints. 7. Policy Formulation and Planning Capacity. An enabling environment for private sector participation requires (i) clear Government policies and rules for independent power generation, (ii) independently priced transmission, and (iii) stronger distribution companies. This Study found that DOE's capacity for policy formulation and rulemaking has not kept pace with the requirements of sector transformation. Moreover, the growing number of decisionmakers within the power sector needing access to adequate and reliable information on supply and demand indicates that weaknesses in the public sector's capacity for planning needs to be remedied. Over the longer term, however, Government agencies' capabilities for data gathering and analysis must be upgraded to provide a reliable stream of information on the status of power projects, thereby reducing uncertainty in planning future supply. Since contracts have already been signed that ensure the provision of enough capacity by 1999, even to meet the highest demand scenarios, the Government does not need to compromise either on the approach it takes to planning, or on the fastidiousness with which it implements the accreditation process. 8. Government Power Sector Objectives. The Government's major power sector goal is to meet all future capacity requirements in collaboration with private developers and private capital. With that goal in hand, NPC and the distribution companies must be restructured and Government agencies strengthened to capture the benefits expected to ensue from privatization. In fact, the realization of these benefits depends in large part on the development of competitive markets for electricity at both the supply and distribution ends of the industry. This study recommends appropriate and achievable changes in the structure and operation of power-related institutions, and it recommends some legal and regulatory adjustments to this end. The interim and final structural changes outlined in this study are believed to be feasible in the Philippines context, where transformation of the power sector is well underway and the Government is prepared to make additional adjustments, within the constraints of current realities. 9. Major Restructuring Issues. Following the Energy Sector Action Plan (ESAP), studies have been conducted to find the best course by which the Government and the power sector can achieve their goals. At this point, three issues dominate: (i) the restructuring and privatization of NPC or some of its parts; (ii) promoting and realizing the benefits of competition as manifested by lower retail prices and the sharing of risks between suppliers and distributors, without the intervention of the Government as an intermediary; and (iii) formulating appropriate future roles of NPC and the Govermment in a transformed power sector. Privatization of generation has grown rapidly, but effective competition and risk sharing have been inhibited by captive relationships, franchise restrictions, and monopolies. NPC is still the dominant supplier in the sector, purchasing for resale more than 80% of planned IPP-produced electricity and assuming most of the market risk as well. NPC would prefer to pass the market risk to the distributors, but most are so weak and fragmented that few IPPs are as yet inclined to deal with them directly. Except for some direct connections to NPC's higher voltage, customers must purchase power from the local distributor. NPC holds a monopoly on the transmission system, and by literal default, responsibility for subtrans- mission systems outside MERALCO's service area. 10. Further Restructuring. NPC has effectively assumed the major role as purchaser and reseller of electricity; this role has been instrumental to the Government-private sector collaboration in addressing the recent shortage crisis. Nevertheless, NPC continues to be subject to demands for greater accountability; this pressure is manifest through a myriad of legislation that calls for the reorganization or dismemberment of NPC. This study found that a major restructuring of the - iv - NPC was inevitable. This study also examined the structure and performance of the distribution subsector, and fbund it needed extensive restructuring in order to enable the market risk to revert to the distribution utilities (where it belongs). C. Realities and Constraints 11. Successful power sector restructuring must take account of constraints that derive from current realities. The structural framework that works best will necessarily be rooted in feasible ad- justments to the status quo; if adjustments are not feasible, then those constraints must be accommodated. These constraints include: (a) Prssure to Privatie NPC. Pressure to reorganize NPC is considerable. DOE has already stretched the ESAP schedule for privatizing NPC. The momentum within the Government, the general public, and the Philippine Congress is to split NPC along regional lines. Riding this wave, the Government must steer regionalization proposals so that actions proposed are comprehensive and appropriate; and so that institutional capabilities are developed for functions that may be retained within the Government's ambit. (b) NPC's Corporate Probkms. NPC is still recovering from a decade of institutional shocks, and faces challenges to its technical, financial, and public credibility: (i) it must rebuild its technical cadre, key elements of which were lost to better-paying competitors; (ii) it must maintain credit only recently rebuilt following years of uneven financial performance; (iii) it must maintain a strong cash position and realize its local currency requirements from revenues; and (iv) it must rebuild the public confidence that was lost during the depth of the power crisis. (c) Condition of Eristing NPC Generating Plants. NPC's thermal generation facilities are old and overworked. As a result, they fall into disrepair more often than they should be for continued dependable production. Because of drought and siltation, NPC's hydro plants operate at reduced capacities. The condition of these plants will likely depress the price they could command in a privatization. (d) Bundled Tunsmission and Underdeveloped Dispatch. As a sponsor of captive IPPs, generation developer, and wholesaler of electricity, NPC cannot serve as sponsor of the IPPs, developer of its own generation capacity, and wholesaler of electricity, and also act as (i) an impartial planner and operator of the transmission system and (ii) formulator of rules of dispatch. In the future, when supply is ample, multiple suppliers will need unbiased access to the transmission system. Therefore, a dispatch entity that is competent to establish fair and transparent rules needs to be developed. (e) Deteriorating Distribution Systems. Almost all distributors have let their networks suffer from underinvestment and neglect of maintenance. The reasons for this vary widely, but the end result is the same -- substantial investment is needed to renew deteriorating assets, over and above requirements for meeting the needs of a growing market. - v - (f) Isln Geography. Geography imposes constraints and costs on the network. The nine largest islands, containing 95% of the population, are served by seven separate grids, most of them too small to optimize. Within each island, the topography and settlement patterns make electrification expensive. (g) Priing and 7hrf(. The Government's pricing policies have been at variance with NPC's supply constraints. As a result, electricity is already very expensive for unsubsidized consumers. The structure of tariffs needs revision to include demand charges. Distorting subsidies need to be eliminated or made fully transparent. Appropriate regimes for wheeling and standby charges need to be developed. (h) Regulation and Rulemaking. As the role of the IPPs increases, so too will the impor- tance of regulation. Yet, ERB has serious capacity constraints, and the Government must support its development and assure adequate funding for its operations. D Proposed Structure for the Power Sector 12. Collaboration Between the Public and Private Sectors. This Study examined several electricity supply and demand scenarios. Including long-deferred replacement of near-failing plants, all scenarios projected capital requirements for generation during 1994-2000 at US$10 billion or more; for the same period, investments in transmission should exceed US$3 billion. Neither the Government nor the private sector, acting alone, can mobilize such amounts. Therefore, the Government and the private sector must continue collaborating constructively for the foreseeable future. For its part, the public sector must focus on two extremely different roles: (a) Maintaining an Orderly Industry. The Government needs to focus on maintaining an enabling environment, within which the private sector can compete without undue constraints. Some laws that enable independent production are currently in place. How- ever, few limitations were placed on (i) the primary fuels or on the technology that an IPP can deploy; (ii) an IPP's ability to sell to the grid or directly to one or more distribution utilities; (iii) guaranteed off-takes through take-or-pay provisions in PPAs; or (iv) the plant factors to be realized by some okf the new facilities. NPC is still for- mulating its policies regarding stand-by capacity and wheeling. Vry little consideration was given to the requirements for economic dispatch. (b) Providing Ekdricity Supples. NPC, either in its present or some unbundled form, must continue operating plants and purchasing generation and stand-by capacity over and above what is provided by the IPPs. Thus, it will continue to be the supplier of last resort and to bear the burden of market risk. The IPPs have thus far shown limited interest in investing in facilities designed to serve lesser markets, and the smaller dis- tribution utilities lack the financial strength or the market attraciveness to make sepa- rate purchase arrangements with the IPPs. - vi - 13. Restructuring of NPC. Recognizing these constraints, this Study developed a restructuring proposal for the power sector, starting with unbundling of NPC. This Study recommends that certain corporate functions remain national in scope: (a) Power System Planning. The Government should retain the responsibility for general coordination of its own and the IPPs' planned additions to the power system. Responsibility for power system planning should be moved from NPC to DOE, but only after the Government furnishes DOE with adequate staff resources to absorb this function. (b) Hydmelctric Development. The harnessing of bydro resources involves several depart- ments of the national Government. Therefore, investments concerning the exploitation of these resources need to be formulated at the national level, and should remain within the ambit of NPC's national headquarters. (c) Backbone Tlnsmission Systems and Dispatch. The backbone transmission system, consisting of facilities for 138kV and above, could still be regionalized. However, responsi- bility for the system should be retained at the national level, so that the priority for inter- connection will not be subordinated to regional concerns. The need to ensure suppliers unrestrained access to the transmission system provides a compelling rationale for creating a transmission company that is distinctly separate from any state enterprise involved in power generation. For the same reason, this proposed new company should also own and operate all facilities for dispatch. The dispatch function must be executed fairly and efficiently. The participation of the Government, NPC, the IPPs and distributors in the formulation of a dispatch entity and dispatch policy can be an outstanding opportunity to reach long-term consensus on those principles and enable a competitive environment for private sector participation. Other major functions, including generation, engineering, procurement, and maintenance are not national in scope, and can be organized on a regional basis (para 15). 14. Charter and Structure of the Iransmission Company. Capitalization requirements for the new backbone transmission company need to be determined by the Government, with independent advice. At the outset, the new company would operate transmission facilities, com- plete projects belonging to NPC, and absorb outstanding associated liabilities. The Government should provide the new company with enough initial working capital so that it can be organized as a commercially operated utility. The company's networks should be available non-discriminatorily to all suppliers, and the rules of dispatch should be transparent. The company's investment program should be approved annually by ERB; and its tariff sbould be based on cost and subject to ERB regulation. While the company should follow commercial operating principles and its cbarter should allow for some future private ownership, scrupulous impartiality should be nurtured by not offering sbares for sale to the public (and risking that one or two suppliers acquire significant ownership) until a bealthy competition among suppliers has been achieved. 15. Regional Subsidiaries. NPC's generation facilities should be spun-off to proposed wholly-owned subsidiary regional companies, functioning as holding companies for existing plants and developers of new state-sponsored thermal generation facilities. This study recommends three such subsidiaries--one each to serve Luzon, the Visayas, and Mindinao. Capitalization plans for these companies remain to be developed; still, creditors will require the subsidiaries to absorb all liabilities related to assets they acquire from NPC. Their charters should enable them to (i) follow commercial operating practices; and, once soundly operated, (ii) sell some of their shares to private - vii - interests. Pursuant to ESAP's commitment for NPC to privatize rehabilitation and operation of existing facilities, the regional companies sbould have the same authority to enter into a broad array of such arrangements with qualified IPPs. However, if the regional companies succeed in imple- menting commercial operating practices for their own plants, they should not be precluded from competing with the IPPs to supply distributors in their areas. 16. NPC wil continue to have a vital headquarters operation in the future. In the near term, it should establish a sound basis for spinning off the transmission company and regional subsidiaries, then help them acquire investment capital and operating credit. Until the regional subsidiaries have developed favorable records for operating and financial performance, the parent could be expected to act as their guarantor. Once the subsidiaries can obtain financing on their own merits, the parent will act more like a holding company; it will (i) assist the subsidiaries with cash management, (ii) collect interest and dividends from the subsidiaries; and (iii) meet its remaiing liabilities. 17. Distribution Consolidation. Because real competition among suppliers depends on the development of more large commercially-viable buyers, the recommended eventual structure depends on consolidation of the distribution utilities. Such a consolidation can lead to needed efficiency reforms. It should be formulated to accommodate the combination of coops and IODs; the general thrust should be shrink the number of small utilities from more than 130 entities to about 15 or even fewer continuous units. Consolidated utilities would reside within natural geographic boundaries defined by NPC's main supply points. While MERALCO would continue to be a domi- nant distribution company, a dozen or more amalgamated 300+ MW utilities can become a competitive market of commercially credible consumers for the IPPs. 18. Until the distribution subsector is consolidated, NPC subsidiaries will be unable to shed some important technical functions, as well as the market risk, which should really be borne by the distribution utilities. Even so, the regionalized parastatal subsidiaries will need to continue buying electricity for resale to the unconsolidated distributors; and the backbone transmission company will need to continue to operate and maintain the subtransmission networks. The process of consolidation could an opportunity to implement transition arrangements that are far more orderly than the current ones, and to develop true competition among IPPs vying to supply electricity to strengthened distribution companies that emerge from consolidation. 19. Subtransmission. While the subtransmisslon systems properly belong with the distributors, virtually all but MERALCO are too weak and fragmented to manage these networks properly. Therefore, the 69kV networks outside of MERALCO's service area should remain with the national transmission company; however these networks should be offered as incentives to distribution utilities to consolidate. 20. Commerce among Producers, Buyers, and Sellers. The proposed structure anticipates and supports competitive market-based contracts among all commercially qualified and credible participants. Impartial and fairly priced dispatch and transmission services would permit buyers to find the most appropriate match of wholesale level supplies, capacity, service, and price. Even as NPC subsidiaries continue to play a role as purchasers and resellers of electricity during transitional arrangements, these reforms are expected to move the power sector toward the Government's goals of ample, appropriate, and competitively priced supplies. 21. Government Agencies and Functions. The proposed framework will continue to involve regulation and monitoring by the Government's energy agencies (eg.DOE, ERB, and NEA). - viii - The study analyzed their current structure and operation, and recommended roles and improvements are offered later in this summary. A major feature of the proposed sector structure is increased reliance on effective competition as a regulator. Except for some minor shifting of functions to strengthen alignment of roles within these agencies, the majority of the structural reform has already been anticipated and authorized by legislation. Significant staff development and organizational strengthening will be required, and they are needed now; these matters are discussed in the recommendations for the interim arrangements. 22. Need for Transitional Arrangements. The recommended framework cannot be implemented before NPC and the distribution utilities are restructured. NPC has already realigned its organization into profit centers, and it has already taken substantial steps toward (i) giving autonomy to transmission opeations, (ii) separating the costs of generation from transmission, and (iii) decen- tralizing the structure of its generation activities. Such arrangements, rooted in decisions of the NPC Board as opposed to legislation, might not accord the necessary independence to the transmission company, but the operational aspects of reorganization could begin. On that basis, NPC and ERB could develop the parameters for wheeling charges and dispatch criteria. 23. On the other hand, the viability of the recommended structural framework depends on the reform of the distribution subsector. In their current fragmented state, distributors other than MERALCO have insufficient levels of demand to attract the attention of the IPPs or to absorb the market risk of PPAs. Many of the others bave been chronically late at paying their bills and have been regarded as marginal credit risks. With few exceptions, they have no alternative but to draw their supplies from NPC since few IPPs would consider taking the commercial risk of serving them unless, they are subjected to a substantive subsector-wide reform process. The recommended structural framework cannot work unless the distribution subsector has been consolidated. Until then, the regionalized parastatal generating companies need to retain the ability to buy electricity for resale to the unconsolidated distributors; and the backbone transmission company will need to operate and maintain the subtransmission networks. 24. Congruence of the Study Proposals with Other Initiatives. On June 10, 1994, NPC's management presented internal reorganization proposals of its own to the National Power Board; these were directed at encouraging and decentralizing management of the various parts and functions of NPC. Proposed subsidiaries include: (i) an NPC Holdings Company, to handle treasury, planning, and centralized dispatch; (ii) a transmission subsidiary to serve Luzon and the Visayas and administer Power Purchase Agreements (PPAs) within these service areas; (iii) an integrated Mindanao Power Corporation, to provide transmission and generation services within that large southern island; (iv) separate subsidiaries for hydropower, geothermal, and barge based (and small island) supplies; and (v) an engineering and maintenance subsidiary to take responsibility for NPC's operational activities. 25. NPC's own draft proposals are generally consistent with those recommended in this Study, and point to similar structures. For example, the few generating plants in the Visayas unaccounted for in NPC's proposals could be bundled with (their) proposed Barge subsidiary to form a company similar to the Visayas Power Corporation recommended by this Study. The principle endorsed by the National Power Board-- operation of NPC's parts as profit centers-- comports with this Study's expressed concern for commercial operation as a prerequisite for continued success in gaining necessary domestic and international financing. 26. The Government's Energy Sector Action Plan (ESAP) committed the Government to policies of privatizing NPC and devolving future power sector development to private interests. - Lx - Several studies commissioned under the Plan examined possible approaches to unbundling NPC. These studies concurred that the unbundled parts of NPC can be managed more effectively than the current Corporation; in contrast, they all but left unanswered questions about how rapidly NPC can be privatized. A receptive market is needed if the Corporation would sell its shares successfully; and the Corporation cannot expect to divest itself of plant and equipment unless those assets are in good condition. Therefore, this Study concluded that the issues of power sector structure and NPC ownership are quite distinct; any recommendations to cbange ownership needs to be feasible, and recommendations regarding structure should not depend on changes to the pattern of ownership. E. Planning, Regulation, Competition, and the Role of Govermnent 27. Financial Implications. Private investments in generation must be integrated with NPC's own generation and transmission investments and with the distribution utilities' investments in network expansion and rehabilitation. At the same time, NPC must maintain its profitability in order to raise official and commercial capital, and structure tariffs to yield revenues adequate to cover the costs of ever more expensive generation from all sources. By efficiently (i) rehabilitating its own power plants, and (ii) improving the technical capacity of the transmission system, NPC can contain the extent of cost increases that must be recovered. 28. Only modest efficiency improvements in the distribution subsector are possible without consolidation. To date, distributors have seen few incentives to grow larger and integrate their service areas, even though larger consolidated companies could better attract effective managers, reduce overhead, and enhance distributors' financial prospects. In particular, bigger, stronger buyers capable of dealing directly with IPPs would also hasten the evolution of the power sector by shouldering the market risk for themselves, thereby enabling the Government to press the IPPs to assume the commercial risk associated with their investments. However, the Government must develop strong incentives for consolidation to occur. 29. Competition and Risk Assumption in the Proposed Structure. To assure ample and efficient long-term supply, the Government needs to (i) create a level playing field for all participants in the sector; (ii) foster competition at both the supply and distribution ends of the industry; and (iii) reduce the layering of institutions between suppliers and consumers. The recommended structure has at its core a separate transmission company that would wheel power between and among NPC's regionalized generation subsidiaries, the IPPs, the large volume higher voltage consumers, and the consolidated distribution companies. The distributors and large volume higher voltage consumers, in turn, would have direct contractual relationships with suppliers, so that they would absorb the market risk. Monopoly and captive relationships among originators, produc- ers, distributors, and large consumers of power would give way to market exchanges among them, subject chiefly to technical and competitive economic considerations. 30. By moving NPC or its subsidiaries away from reselling energy, consumers and weaker participants in the power sector will be less protected from supply and price risks. These risks can be minimized and managed by a stronger DOE through its exercise of enhanced planning and accrediting functions. DOE will need to maintain a current and detailed inventory of all planned and ongoing IPP activity; and its accreditation process will need to be tightened to ensure that each new development is rationally financed and fits into a general system plan. 31. Directly Connected Customers and Wheeling. Some 91 consumers now receive electricity at 69kV directly from NPC. Under the proposed new structure, consumers with monthly loads over 5 MW and financial credibility will be able purchase supplies directly from IPPs, NPC subsidiaries, or their local distributors, paying suppliers for energy, NPC for wheeling related to transmission, and local distributors for wheeling related to subtransmission (where appropriate). 32. The Role of Regulation. Because the recommended structure anticipates and supports direct contact between suppliers and distributors, it also has the important advantage of relying less on Government regulation than several alternative frameworks that were considered. In effect, competitive market forces would protect the consumer as well as the regulatory process might. ERB would continue regulating the distributors' tariffs since they would effectively continue to have protected monopolies; moreover, since this model would continue to feature long-term supply contracts, the distributors would benefit from ERB conducting a prior review of provisions of those agreements related to distributors' ability to pass-on properly incurred energy and power costs. To strengthen its capacity, ERB would still need to undergo a substantial institution building effort; in addition, ERB needs to recruit more qualified staff and charge a regulatory fee to defray its ex- penses. 33. Load Dispatch. Implementing a fair and transparent load dispatch system appears to be one of the most important residual future roles in the power sector for the Government. Load dis- patch should be linked to operation of the transmission system; that linkage appears to have advantages in the Philippines, where no precedent exists for collaborative pooling among competing suppliers. As substantial additions to capacity come on line, the dispatcher will determine the order with which plants are brought on line so as to minimize consumers' costs. However, provisions will be needed to honor NPC-executed PPAs that guarantee a high off-take for some relatively high cost electricity. 34. Technically, dispatch is an adjunct to transmission; and the dispatch function should be performed by an independent dispatch entity located at and as a part of the proposed new transmis- sion company. The forerunner of this dispatch entity should be a preliminary technical Coordination Committee, composed of representatives of parties to existing power generation contracts, with ERB and DOE as advisors. Its purpose will be to formulate rules and priorities for dispatch, and to design a framework for the evaluation of financial risks of existing contracts. With the eventual creation of a power pool, this Committee will evolve into a permanent Committee with similar dispatch rulemaking authority. 35. Recommended Roles of the Government Power Sector Agencies. The framework for the eventual structure and arrangements during the transitional period rests on rationalized rmles of the Government agencies participating in the sector: (a) DOE should serve mainly as the policy maker for the sector. DOE should provide clear vision on strategic issues and clear rules forming the framework within which the regulator can adjudicate. DOE should become more fully capable and then responsible for developing the strategic plan for sector development. Because DOE is in a position to span the entire range of the power sector without conflict of interest, it should take responsibility for accrediting IPP proposals and for maintaining a comprehensive, up- to-date inventory of all power developments nationwide. (b) NPC, through its subsidiaries, should limit its role to being an owner and sometime operator of generating facilities. It should retain lead responsibility for developing - Xi - hydrpower projects, and should be one of many suppliers of thermal electricity, all competing on equal commercial footing. In the near term until DOE develops the needed capabilities, NPC should continue as the agency responsible for powver sector planning. Also in the intermediate term, until distribution subsector reform has taken root, NPC will need to continue as the wholesaler of electricity. (c) The new national transmission company should serve strictly as an owner, developer, and operator of high voltage networks, providing all suppliers with nondiscriminatory access to the system for a fee. To ensure adequate and timely service, it should submit its investment program annually to ERB for approval. To ensure that its charges are fair, its cost-based rates should be subject to regulation. (d) NEA's should shed some peripheral activities and focus on its current primary role, that of an interested lender for subtransmission and distribution systems. To facilitate distribution utility consolidations, NEA should be encouraged to lend to the IODs with at least the same priority it has traditionally accorded coops. NEA's role in the pro- gram to reform the distribution subsector can be pivotal, as it could provide guidelines, and the distributors themselves could be invited to formulate the consolidation frame- work. However, NEA lacks some of the institutional capacity needed to spearhead the proposed consolidation of the distribution utilities, and it should therefore by strengthened. In addition, NEA's ability to deal with issues of credit and financial engi- neering will need reinforcement. (e) ERB should remain a quasi-judicial agency for regulating mainly the tariffs of all com- panies that qualify as electric utilities. However, the approach to regulation should rely most heavily on market forces and thereby limit the interventions of the regulator. ERB's span of jurisdiction should be altered to include the power to award franchises, thereby bringing franchising and certification activities under the same organization (para 38). (f) A dispatch entity needs to be created, as described above (para 30). The rules for dispatch should initially be made by a technical committee consisting of representatives of parties to existing power sales contracts, with advice from DOE and ERB. These roles will enable the various Government agencies to create the proper environment for encouraging the continued momentum of the private sector for developing power sector facilities. Where market forces are not yet strong enough to drive sector development, these roles will permit the Government to fill those voids. 36. Policies for Consolidation of Distribution Utilities. Legislation to restructure the power sector should include policies on consolidation of distribution utilities. At the outset, the distributors should be invited to formulate their own consolidation programs; however if they fail to do so within a reasonable time-frame, NEA should issue detailed guidelines for accomplishing this objective. The Government could offer incentives to distribution utilities that do consolidate, and impose price and tax disincentives on those that prefer the status quo. The leading incentive is the 69kV subtransmission system, by which distributors with solid financial and commercial potential can earn wheeling and possibly supply charges for serving their areas' medium and higher voltage consumers. NEA should encourage the consolidation of distributors by making the availability of credit much more stringent for those refusing to combine. - Xii - 37. Enhanced Regulatory Capacity. Structural changes in the sector have already placed new pressures on the country's regulatory capabilities. While DOE, ERB, and NEA are generally performing well, the size and technical complexity of the increased work load necessitates a major increase in staffing as well as additional training for new and existing regulatory staff. These agencies need to become quickly capable of dealing with: (i) the rapid increase in IPP involvement in the sector; (iu) legally mandated shifts in organizational responsibilities among the agencies; and (iii) the anticipated direct interaction between suppliers and consolidated distributors. 38. NEA has performed creditably as the regulator of the coops through 1992. However, with the passage of the Department of Energy Law, that function was transferred to ERB. In order to enable this recent allocation of regulatory responsibility to function effectively, additional legislation will be needed to transfer responsibility for awarding electric utility franchises from NEA to ERB. This would consolidate the authority to award franchises and to certify distributors within one agency--ERB. The effective tmnsfer of franchising responsibility will relieve NEA of inherent conflicts between its roles as lender and quasi-regulator, while consolidating ERB's legal and technical authority. 39. Recommended Types of Regulation. This Study recommends continuation of rate- of-return regulation. ERB was developed according to the U.S. regulatory model, and its staff has developed expertise with regard to U.S.-based systems. At a time when ERB is struggling to expand its capacity to service 135 distribution utilities and NPC on a timely basis, it cannot also change its approach to regulation. At the same time, the lODs and NPC are all legally required to limit their financial performance to less than the maximum level stipulated by their charters. As a result, they are subject to a modified version of price cap regulation. F. Recommendations to Enable the Environment for Competition 40. The most important objective of the enabling environment is uniform market arrangements for all participants. To develop this rapidly, the Government needs to address specific issues related to pricing, dispatch and regulation, in addition to the restructuring proposals discussed above. 41. Tariff Reform. Higher voltage power tariffs should by structured to reflect costs. This Study revalidated previous Bank recommendations to: (i) unbundle fixed and variable costs within tariffs, and (ii) introduce time-of-day differentials, at least for higb and medium voltage consumers. Tariffs should unbundle the cost-based components of energy and capacity in order to end inter-regional distortions and stimulate demand side management. At the retail level, residential subsidies should be eliminated over a five-year period, enabling distributors to lower their rates to larger higher voltage consumers or risk losing them to less expensive wheeled supplies. Tariffs must explicitly include costs of stand-by capacity; otherwise self-generation will remain an attractive and implicitly subsidized alternative, and will continue to remain a random component in forecasts of power supply and demand. Moreover, at the wholesale level, pricing of power in the different re- gions should reflect the true costs of generation and transmission. Current inter-regional cross- subsidies have served as a substantial disincentive to IPPs interested in locating plants in the Visayas or Mindanao. - Xiii - 42. Wheeling Charges. The development of independent transmission is necessary for competition. Separation of transmission costs and development of wheeling charges as part of the tariff for energy can be developed and later applied to the bulk transfer of electricity between buyers and sellers in the power sector. In order to encourage IPPs to site their plants at favorable locations without losing the flexibility to identify the best possible selling arrangements, an acceptable framework for wheeling charges over the transmission and subtransmission systems is needed. 43. Taxation. Taxation of fuels for power generations needs to be rationalized. To enable all suppliers of electricity to pay the same amount for fuels while shouldering the fuel supply risks for themselves, this study recommends that fuel tax exemptions should be extended to the IPPs; since the IPPs have been avoiding this tax by engaging in energy-conversion contracts with NPC the Government would not be foregoing any existing tax revenues. Equal treatment of all suppliers could similarly be achieved by eliminating the fuel-tax exemption entirely; however, this would require a politically difficult 10-15% increase in retail electricity prices without concomitant improvements in service. G. Conclusion 44. The measures employed to resolve the power crisis of 1992-93 are the leading edge of a major transformation of the Philippine power sector. The Government should now guide this ongo- ing transformation so that private development becomes self-sustaining, and the private sector participates in the spate of sector development prospects, not just those few that are particularly f- vorable financially. The Govermment can do this by (i) simplifying the structure and roles of public agencies participating in the sector; (ii) taking necessary steps to support development of market tansactions in wheeled electricity over transparently operated transmission and subtransmission systems; and (iii) encouraging balanced market power between private companies in the generation and distribution subsectors. The principal objective of these agencies and the opening of the transmission system should be to encourage a business climate in which the private sector can flourish. 45. This study has developed a structural model based entirely on Philippine circumstances, with due consideration for the history of the power sector and the constraints which caused the recent and rapid transformation of the supply side of the sector. It does borrow from several of the other models where appropriate. But, the parameters have been designed to address Philippine issues, and efforts were made to test the feasibility of the recommended framework against Philippine problems. Therefore, the recommended structural framework is considered to be a uniquely Philippine model. I 1. Realities and Constraints A. Introduction 1.1 Since the Bank's Energy Sector Study in 1988, the Philippines has experienced a major crisis of electricity supply. At the depths of the crisis in 1992-1993, brown-outs averaging seven hours per day were common in many regions of the country. Ironically, the crisis followed the Government's substantial steps to strengthen the National Power Corporation (NPC) operationally and financially. Moreover, because existing capacity was considered sufficient to meet increases in demand projected through about 1991, NPC did have sufficient lead time to implement least- cost additions to its generating capacity. 1.2 During the period 1988-1992, (i) NPC was subjected to new regulations standardizing all Government agencies, (ii) the tariff adjustment process became politicized, so that the Company's operating and financial capacity became constrained, and (iii) the Company did not make effective use of available lead time to implement investments in needed new capacity. During that same pe- riod, persistent drought conditions resulting from the El Nino phenomenon limited the country's hydroelectric output (especially in Mindanao), and thereby exacerbated the growing capacity con- straints. These constraints grew tighter as environmental clearances for several fully financed NPC initiatives to add coal-fired capacity to the Luzon grid were delayed because of protests from affected local populations. 1.3 In 1990, when NPC assessed the impact of delays in its program to provide new capac- ity and began facing the certainty of supply shortages in Luzon for 1991 and beyond, the Company determined to supplement its own efforts with private development of generating facilities. The first such initiative, a 200 MW peaking plant at Navotas developed by Hopewell Holdings under a Build- Operate-Transfer (BOT) arrangement, was synchronized with the Luzon grid in less than two years. 1.4 In many respects, that project was beneficial for all parties. Most importantly, that project showed that the Government could collaborate witf private interests to make timely additions to generation capacity. The project proved to the Government that its own resource and absorptive capacity constraints need not unduly limit the development of the power sector; and it opened up prospects for the private power developers that the Philippines might be a hospitable country for pursuing business opportunities. This project was the forerunner, then, of a broader program to devolve to the private sector broad responsibility for power sector development. 1.5 On a project specific basis, the Navotas project produced ambivalent results. By pur- chasing a used plant in good condition, Hopewell could implement the project quickly at low cost; and it passed some of the savings on to NPC. However, NPC is assuming the fuel supply risk for the life of the project, and the Government agreed to guarantee NPC's commercial obligations under the Power Purchase Agreement (PPA). Also, the PPA included (i) a guaranteed off-take through a take-or-pay provision, and (ii) substantive incentives to exceed that off-take and thereby run the facility as a base load or intermediate plant. These features, which limited the commercial risk being borne by Hopewell, were appropriate to a circumstance where a developer was venturing a substan- tial long term investment in a country that had theretofore had no experience with Independent Pow- er Producers (IPP). 1.6 As the capacity shortages became a crisis, the Government pressed for additional pri- vate sector developed projects, following the Navotas model. Within a year, the Government had committed to another dozen BOT or Build-Transfer-Operate (BIO) schemes. A number of these ini- tiatives came under a special program, implemented in July 1992 during the first weeks of the Ramos Administration, to install 1000 MW on a 'fast-track". Most of the 'fast track" plants are gas turbines, which are characterized by the low capital cost, short construction period, and high opera- tional costs typical of peaking facilities; however, for these additions to capacity to meet suppressed demand, they are run at plant factors more appropriate for base load facilities. 1.7 As of mid-1994, the Philippines was well on its way toward a broad and self-sustaining collaboration between private and public interests to supply the nation's electricity needs. Therefore, this appears to be a propitious time to assess the country's early experience with this collaborative process. This study will attempt to draw from the lessons of the past, recommendations for how to adjust the structural framework and the enabling environment so that development of the power sector in the future will be orderly and cost effective. B. Current Sector Structure Framework for Government Control 1.8 Until 1986, all primary energy sector institutions fell within the ambit of the Ministry of Energy. PNOC served the retail market for coal and oil-based products in addition to its primary activity as developer and converter of primary energy resources. In turn, NPC was the monopoly supplier of electricity at the wholesale level; some 15 investor owned utilities (lODs)(including the Manila Electric Company [MERALCO]) and about 120 member owned rural electric cooperatives provided service to consumers at the retail level. The Ministry of Energy was neither directly nor indirectly involved with the distribution utilities. The Energy Regulatory Board (ERB), an agency of the Office of the President, ensured adherence of the investor-owned utilities with Government poli- cies through its authority to regulate their rates. NEA, then an agency of the Ministry of Human Settlements, enforced Government policy on the coops by setting their rates and serving as their conduit for concessionary borrowings. 1.9 In 1986, the Government disbanded the Ministry of Energy; its research functions were assigned to the newly created Office of Energy Affairs (OEA), while PNOC and NPC both were as- signed to the Office of the President. To improve coordination between the various Government energy agencies, the Government created the Energy Coordinating Council (ECC) in 1989; the Exec- utive Secretary chaired the Council; OEA served as its Secretariat; and PNOC, NPC and NEA were its permanent members. This arrangement was flawed in that ECC had no legal authority to make or enforce decisions. To remedy this, the Government created the Department of Energy (DOE) in 1992, and PNOC, NPC and NEA were all brought under its control. The Secretary of Energy be- came the ex-officio Chairman of PNOC and NPC; he was also legally empowered to serve as the Chairman of NEA unless the President appointed someone else (this did happen). OEA was folded into DOE, and most of OEA's staff were transferred into the Department's key positions. Under the new arrangement, ERB continues to report to the Office of the President, and its regulatory scope has been extended to cover NPC and the coops in addition to the investor-owned utilities. -3 - The Generation Subsector 1.10 The private development of electric facilities is not a new phenomenon in the Philip- pines. Until 1973, virtually all power facilities were developed by private interests; in effect most load centers in Luzon as well as the larger cities in the Visayas and Mindanao were served by verti- cally integrated investor owned businesses that supplied limited areas. The only significant Govern- ment interest in the power sector was NPC, which had responsibility for developing the country's hydroelectric facilities. This was justified on the grounds that (i) decisions with regard to the devel- opment of particular hydro sites required inputs from and had an impact on a number of other sec- tors of the economy; and (ii) the construction of hydro facilities involved capital investments so large that only the Govermment was thought to have the needed resource mobilization capacity. Shortly after the imposition of Martial Law, the Government enunciated through Presidential Directive [P.D.] 40) a new policy which concentrated all generation and transmission facilities nation-wide in one state owned monopoly, namely NPC. As a byproduct of that policy, the Government could implement social pricing policies that kept electricity prices low for residential and other small con- sumers that are expensive to supply. As recently as 1979, private interests were being pressured to sell their generating plants to NPC. 1.11 This former policy was partially revrsed in 1987, when the Government promulgated Executive Order (E.O.) 215 that ended NPC's monopoly on generation facilities. This measure was designed to accommodate the Philippine National Oil Company (PNOC), which could not sell the geothermal steam it was developing to NPC because the Government's required royalty on this resource raised the cost of geothermal steam powered electricity well above that of coal and oil fired alternatives. The possibility that E.O. 215 would reopen the door for privately developed generation was discounted on the basis that (i) the extent of long term capital required was greater than domes- tic private interests were likely to mobilize, and (ii) laws restricting foreign ownership of utilities would likely deter foreign investors from entering this business. However, as the power crisis deep- ened and private development came to be viewed as the only viable approach for quickly addressing the shortages, the Government committed itself to developing a full fledged plan for privatizing the power sector. In that context, it developed the legal framework to enable foreign interests to own and operate generating facilities. At this point, most of the IPPs currently constructing power facili- ties or promoting new ones, are foreign. 1.12 Despite the growing involvement of private developers in generation, NPC is still the monopoly supplier to all electric distributors. This Government monopoly is expected to continue for the foreseeable future. Until 1991, NPC interpreted E.O. 215 as narrowly enabling the independent production of electricity, but not direct supplies to distributors by IPPs. As a result, the vast majority of IPPs have arranged their PPAs with NPC; and NPC supplies that throughput to their clients as traders rather than producers of electricity. However, as the shortage crisis deepened, the Govern- ment could not run the political risk of appearing to restrict supplies; therefore, it allowed the ac- creditation of several IPP proposals to supply MERALCO directly. In short order, MERALCO and about five of the more prosperous distributors were actively pursuing such arrangements. However, as of November 1993, just three modestly sized projects were confirmed, fully financed and being implemented: the Subic Bay Metropolitan Authority (SBMA) and two Export Processing Zones in Central Luzon, all due for completion by 1995-96. In the longer term, NPC's predominance in the generation subsector will be tested after MERALCO begins purchasing significant amounts of its supplies directly from IPPs. -4- Transmission and Distribution 1.13 Currently, NPC has a monopoly on all transmission services nationwide. NPC owns most high voltage transmission lines and intermediate voltage subtransmission facilities; while MIERALCO owns some higher voltage (69kV and 138kV) lines, it uses them only to draw electricity from NPC's delivery points on the fringes of its service area into its urban core. So far, the private sector has not made a serious offer to develop transmission facilities; and none is expected until the Government develops the detals of policies concerning (i) wheeling charges, and (ii) the disposition of the higher voltage consumers currently being served by NPC. Until these policies are defined, potential offerors cannot assess their prospective returns. NPC has expressed an interest in divesting itself of the subtransmission networks; however, few of the distribution utilities have the institutional and financial capabilities to manage these facilities properly. 1.14 While the Government through NPC has dominated the generation subsector until recently, responsibility for developing the distribution subsector has been allocated entirely to some 135 investor or member owned private utilities who have exclusive rights to provide medium and low voltage service within their franchise areas and who are all subject to price regulation. Only MERALCO is of substantial size and with established international commercial credit. Some five other IODs and three member owned cooperatives are medium sized utilities with service areas that include a large urban core. The remainder are modest operations that serve small towns, villages and rural areas. NEA is the Government agency that acts as an interested lender providing subsidized loans and specialized technical assistance to the member owned cooperatives. At the time of the Energy Sector Study, the distribution utilities had serious operating and financial deficiencies. Since then, many distributors have ralized major improvement, thanks in part to interventions by the Bank; however, their operational performance still has considerable scope for further improvement. Many of these utilities have expressed an interest in broadening their activities; and NPC has been seeking to devolve increasing responsibility for sector development to them. C Objective of the Study 1.15 These trends toward increased private development of the power sector, taken together, indicate that a major transformation in the structure of the power sector is already taking place. While the Government is addressing many of the constraints lo private sector led growth in this sector, little attention has been paid to ensuring that the structural framework resulting from this transformation will serve the national interest. Only recently have Philippine authorities begun debat- ing the objectives for that long term structural framework and how to guide the ongoing transforma- tion. Therefore, the principal objective of this study is assist the Government by deriving the struc- tural framework for the power sector in the post-privatization period. 1.16 To manage the new private participants, the restructured power sector will require a well coordinated set of Government institutions with a solid professional capacity to (i) formulate policy, and (ii) lead and coordinate the IPPs. This will surely involve an enhanced role for DOE. The framework for the Government institutions as developed by the Department of Energy Act of 1992 appears sound. However, this study found that needed regulations, project approvals, policy decisions, and planning guidance were delayed during official review or were not being executed at all. These problems were associated with overlaps between (i) DOE's policy-making functions and ERB's regulatory responsibilities; (ii) DOE's responsibility for energy planning and NPC's responsi- bility for electricity system planning; (iii) DOE's role as administrator of the IPP program, NPC's authority to accredit IPP proposals, and the National Economic Development Authority's (NEDA) - 5 - responsibility to clear IPP projects. The organizations in question coordinate poorly and so have either worked at cross purposes or alternatively left important functions unfulfilled. Moreover, while DOE inherited from OEA a strong cadre of research oriented staff, it should strengthen its capacity for institutional coordination and policy development. In the face of these institutional weaknesses, dominant IPPs have been free to self-interestedly define most of the sector's new business practices. The challenge for the Government is to regain control over those business practices, and thereby fos- ter competition. 1.17 The private sector was invited to help relieve temporary capacity shortages in the Philippine power sector, but its role will perforce increase still further since the power sector's needs have by far outstripped the capacity of the Government. The magnitude of requirements and the need for orderly processes as the Government redefines its role, suggest that the public and private sectors will need to collaborate constructively for some time to come. 1.18 For the Philippine consumer, competition and its fruits are essential ingredients of sector reform. Electricity is already expensive for unsubsidized consumers, so new investment must be cost effective. The consumer cannot bear continued brown-outs, and cannot afford to pay for too much capacity either. Projects need to be started and completed on time, and all assets need to be operated efficiently. The private sector can produce these results. To participate in force, the private sector requires a business climate within which it can flourish. The ensuing chapters of this report will focus, inter alia, on resolving issues at the interface of the public and private sectors, and on corresponding improvements to the business climate. 1.19 All too often, opening up the supply side of electricity to IPPs has been equated with introducing competition; and efficiency, cost effectiveness, and additional financing are expected to follow directly from having more than one supplier. The Philippine experience shows that the devel- opment of competition depends as much on reform at the demand side as at the supply side of the business. Now that the sector has been opened to multiple suppliers, the most important pending reform is at the distribution end. Unless the distribution utilities have comparable strength with the IPPs, monopoly will merely be supplanted by monopsony. 1.20 The success of any power sector restructuring depends on how well it takes account of the issues that derive from current realities. The most important of these issues relate to planning and investments, and they will be elaborated in Chapter 2. Another broad set of issues relate to finance and tariffs; they will be elaborated in Chapter 3. A more gencral set of structural issues arise from the sector's existing realities, and these will be elaborated in this chapter's following paragraphs. The spate of existing issues and constraints will preclude some alternative structures and impose limitations on many others. While the remainder of this report will analyze the leading requirements of sector structure, the structural framework that works best will necessarily be rooted in making feasible adjustments to the status quo. D. Current Realities and Derivative Issues Privatization PNlicy 1.21 During 1992, as the shortage crisis was deepening, the Government urgently developed a broad based Energy Sector Action Plan (ESAP). In December 1992, DOE adopted ESAP as the road map for the future development of the sector. ESAP committed the Goverment to privatize NPC, and it allowed a year for study and development of proposals. DOE is now stretching the schedule to enable more careful consideration of the objectives for privatizing NPC, and the best ap- proach for realizing those objectives. However, the momentum within the Government and among the general public to restructure NPC is very strong, and some decisions are bound to be made within the next few months, whether or not preparations are adequate. 1.22 Several bills have been introduced in the Philippine Congress to split NPC along re- gional lines, reflecting this momentum and responding to pressure from the business community within the regions. None of them addresses satisfactorily the complications from proposed regionalization; but all generally anticipate that (i) the regional companies would sell bonds and shares to the public in the medium term, and (ii) private interests would be engaged to operate and maintain the NPC plants that they stand to inherit. Because of this pressure, regionalization of NPC in some form appears inevitable in the medium term. The challenge for the Government is to formu- late the details of regionalization so that (i) the actions proposed are comprehensive and appropriate; and (ii) institutional capabilities are developed for functions that may be retained within the Govern- ment's ambit. NPC's Corporate Problems 1.23 In parallel with the power crisis, NPC faced some serious corporate problems: (a) During the mid-1980s, a large number of promising NPC technical staff left to take highly paid jobs in the Middle East. Subsequently, many other NPC technical staff left on account of salary standardization with the rest of the Government. Even if the Presi- dent were to use his authority under the Emergency Powers Act raise NPC salaries, NPC would have a difficult job rebuilding its technical cadre. (b) Since 1988, NPC's annual financial performance has been uneven. As a result, NPC has had difficulty maintaining its credit. NPC did post good results in 1992, and hopes for similarly good results in 1993; thus, it did regain some of its financial standing, as evinced by the successful closing in November 1993 of a public offering of five year Eurodollar Bonds (backed by the guarantee of the Republic). (c) The uncertainty of tariff revenues is especially relevant in the context of NPC's local currency requirements. The Philippine financial markets do not offer a debt instrument with a term of more than three years. Funding of such short term has limited useful- ness to a capital intensive utility; therfore, NPC must realize all of its local currency requirements from tariff revenues. Thus, the cash flow constraints resulting from the politicization of its tariff induced NPC to develop undue foreign exchange exposure and a bias for imported goods and equipment. (d) MPC must now rebuild the public confidence that was lost during the depth of the power crisis. This is especially important in view of the upward pressure likely to be exerted on a tariff that is already among the highest in East Asia (para. 1.34). Condition of Existing Generating Plants 1.24 The average age of NPC's thermal plants is 23 years. Over the years, those thermal plants have not been taken out of service for regular maintenance; moreover, they have been pushed for long periods at very high load factors. Thus, they have suffered serious deterioration and are in -7 - poor condition even for their advanced age. Virtually all are operating at well below their rated ca- pacity. 1.25 NPC's hydro plants are also operating at reduced capacity, although the plants them- selves are in reasonable condition. The plants at Pantabagan and Ambuklao in northern Luzon did suffer some damage during the 1990 earthquake; but, their supply constraints result largely from drought, siltation of their reservoirs, and priorities accorded to agricultural and potable water. In Mindanao, which is powered by a virtually all hydro system, the twelve hour a day shortages of 1992 came about because the drawdown of Lake Lanao to precarious levels was followed by a lengthy drought. The challenge for NPC is to keep the hydrology of these plants from becoming irreparably damaged. 1.26 The weak operational condition of existing generating facilities raises two important issues: (i) the age and suspect reliability of these plants mean that new plants will be needed not only to meet the capacity deficit but also retire a large number of them; and (ii) the concern about their condition will likely reduce their salability in a privatization or depress the price these plants could command to politically unfeasible levels. The aggregate investment requirements between now and the year 2000 for new generation, whether from NPC's own resources or through IPP arrangements, are estimated at USSIO billion; about one third of that amount would cover the retirement of deterio- rated (para. 1.24) or economically obsolete plants. As expected, several potential buyers or lessors of these thermal plants have indicated that any offers would depend on a thorough inspection of these plants' boilers, generating islands, and turbines. The market price these plants will command is di- rectly related to expectations of the cost of returning them to good operating condition. Tansmission and Dispatch 1.27 The current structure (para. 1.13), where NPC owns the transmission system and is itself responsible for dispatch, led to orderly sequencing of plants as long as NPC also owned all generating facilities. This structure could also function uncontentiously under recent conditions, when available supply from multiple generators has been insufficient to satisfy demand. However, this structure will need adaptation to take account of the many outstanding PPAs that cover: (i) sales to NPC with take-or-pay provisions for significant amounts of electricity at price levels higher than might otherwise be available, and (ii) direct sales to distribution utilities also with take-or-pay provi- sions for consequential amounts of electricity. In the future, all generators will need assured unbi- ased access to the system, subject to wheeling charges that fairly cover the full costs of transmission. Similarly, the rules of dispatch will need to take account of existing contractual arrangements, and the body setting those rules should be perceived as free of bias. Deteriorating Distribution Systems 1.28 During 1981-91, almost all distribution utilities experienced serious cash flow con- straints and responded by curtailing investment and maintenance. Now, almost all need to strengthen and modernize their existing systems while expanding in order to meet load growth, but their pros- pects for doing so vary: (a) MERALCO's previous ownership group acquired the Company using a self-liquidating transaction. As a result, the Company was pressed to curtail investments, maintenance and human resource development in order to sustain the level of its dividends. Follow- ing the 1986 change in control, the Company became concerned about the state of its network; however, its access to investment capital was limited by (i) its own poor - 8 - credit, and (ii) unfavorable perceptions about the Philippines in international financial markets. By 1989, the Government enabled MERALCO to have temporary access to official loans. In January 1993, the Company floated a successful primary issue of common stock through a successful world wide public offering. Now, the Company can access commercial credit, although not in the amounts sought or for the term de- sired. (b) During 1969-83, electrification of the entire country was a major Government objec- tive. NEA solicited substantial concessionary loans and onlent the proceeds to the coops with minimal spreads. While ample funding was available for investment, tariff revenues were insufficient for many of the coops to cover maintenance costs on exist- ing systems; consequently, core systems in need of refurbishing were left untended. During 1983-91, as the bilaterals curtailed funding for investments in this sector, the coops neglected maintenance even of newly developed systems. Most coops are facing major refurbishing programs; these programs form the core of the Bank financed Runl Electrification Revitalization Prject (RERP)(Loan 3439-Ph). (c) The IODs are generally family enterprises that serve some twelve cities other than Metro Manila. The quality of their assets and management vary widely. Some of them (Cagayan Electric Power and Light Company, Cotabato Light and Power, and Angeles Electric Company) have done a good job of maintaining their networks. The condition of the others' networks varies from undistinguished to very poor. Most of these compa- nies have had difficulty securing credit, and their access to official funding has been constrained by the lack of an appropriate financial intermediary. While NEA has the qualifications, it is not considered legally eligible to lend to these utilities. 1.29 The subtransmission networks were originally owned and operated by the distribution utilities; bowever, since the distributors allowed these lines to fall into disrepair, NPC absorbed them into its network by 1981. NPC currently regards these networks as the orphans of the transmission system, and has indicated its willingness to return them to the distributors. Nationwide, these net- works are generally in need of substantial refurbishing; however, few distributors currently have the institutional or financial capability to maintain them. 1.30 Aside from MERALCO, the distribution utilities are generally small and financially weak companies. Individually, they have virtually no business leverage; yet their interests are too fragmented to enable their routinely combining for mutual benefit. This will become evident as more generation is provided by IPPs. Since these utilities have very little strength to negotiate directly with suppliers, they will be left to follow the terms established for them by NPC or MERALCO. Mean- while, NPC and MERALCO, the only available strong, smart buyers for IPP supplies, are not in competition with one another. Since the Government is legally authorized to guarantee NPC's com- mercial obligations, IPPs wanting to offset commercial risk prefer BOT arrangements with NPC as their purchaser. Conversely, since MERALCO buys for resale to end-consumers, it can afford to pay more than NPC; therefore IPPs willing to assume more risk for a higher price prefer BOO arrange- ments with MERALCO as their client. This weakness at the distribution end of the sector would seem to inhibit true competition more than any condition existing at the generation end. 1.31 The condition of distribution networks nationwide is indicative of the chronic underfunding throughout the sector, regardless of whether the utility is privately owned or a Govern- ment company. The nrsons for underfunding differ widely -- some utilities were unable to raise investment finance; others had difficulty implementing investments once the funding had been raised; and still others placed a higher priority on distributions from profits than on system renewals. Unmet needs are the same, however--substantial investments to renew deteriorating assets, over and above those required to serve a growing market. Impact of Island Geography 1.32 The Philippines is comprised of over 7,000 islands. The largest is Luzon, about 104,000 sq. km in size and bearing a population of about 38 million. Mindanao comes next (94,000 sq. km. and 14 million people). The only other island with appreciable population density is Cebu. Fmm an electric system perspective, Luzon is comparable to a country of modest size. The network is substantial and can be optimized; however, the terrain is rugged and must be ringed rather than crossed. Mindanao is comparable to a much smaller country; each new generating plant represents a lumpy increment of supply. There too, the rugged terrain has resulted in ribbons of development along the perimeter. Because most other islands are small, efficiencies of scale are difficult to real- ize, and electricity supplies are generally expensive. The islands that are electrified generally have mountainous central spines, so the bulk of development is along the shore. 1.33 The island geography imposes constraints and costs on the network. The nine largest islands, containing 95% of the population, are served by seven separate grids (five in the Visayas alone). While Luzon and the eastern Visayas should be interconnected by 1998, the further intercon- nection of the western Visayas and Mindanao is not yet economically justifiable. Within each island, the topography and settlement patterns make electrification expensive, and the smaller and poorer islands are also the ones with the most expensive supplies and the costliest networks. NPC has been committed since 1988 to substantially escalating subsidization of supplies to about a dozen small is- lands that consume less than 1 % of its production. Pricing Polices and Tariffs 1.34 For many years, the Government's pricing policies have been at cross purposes with NPC's supply constraints: (a) The overall level of retail tariffs in the Philippines is by far the highest in Southeast Asia, and is second to Japan among all Asian countries; consumers in some of the smaller, poorer islands pay nearly three times the mtes charged in Washington, D.C., despite substantial subsidies in the cost of supply. Because retail rates are high, resi- dential or small business consumers (especially in semi-urban and rural areas) have reduced their consumption to low and inelastic levels. The ability of the vast majority of consumers to continue affording real tariff increases has already been stretched. These consumers' aggregate consumption is so small that, while substantial tariff in- creases will surely involve hardship for them, their additional payments will only mod- estly increase total revenue. (b) Since the late 1960s, NPC's tariffs to distribution utilities and industrial consumers alike have included only nominal demand charges. This has resulted in a nation-wide proliferation of low cost, energy inefficient industrial machines and major appliances. Even in the face of the recent power crisis, consumers have had little incentive to shoulder the cost of retrofitting equipment for enhanced efficiency. (c) The combination of Government policies to (i) cross-subsidize consumption in the Visayas and Mindanao with higher rates in Luzon, and (ii) subsidize significantly a - 10 - lifeline block of consumption, leaves MERALCO and most other distribution utilities in Luzon with very little flexibility in setting prices for industrial consumers. Thus, the distribution utilities have been effectively precluded from competing with NPC to serve the higher voltage consumers currently being supplied by NPC. (d) Consumers relying on auto-generation have maintained free-of-charge stand-by connec- tions with NPC or their local distributor. To beat the shortages, some 1,600 MW of gensets were imported into the Philippines during 1993. Their owners are expected to keep using them for the foreseeable future while also maintaining stand-by connections. Utilities bear the cost of capacity to supply all connected customers, but do not collect revenue from the portion of their capacity which duplicates what the auto-generators are using to supply themselves. This must result in higher electricity charges to all other consumers. Clearly, the question of stand-by charges cannot be raised while the shortage situation persists; however, this issue will need to be raised when the immedi- ate crisis has passed. Regulatory Framework 1.35 The electric sector in the Philippines was patterned on the US model. As a result, the distributors' rates to end users have been regulated. As of 1986, ERB had the responsibility for regulating the rates of the lODs, while NEA was charged with regulating the rates of the member owned coops. NPC was not subject to external regulation; its prices were set by its Board of Direc- tors, after informal consultations with the Office of the President. In December 1992, the Energy Sector Act accorded ERB the responsibility for regulating all distribution utilities and NPC. Howev- er, the IPPs are not subject to regulation; and no provision has been made for ERB to conduct a prior review of the take-or-pay contracts between the IPPs and the various utilities whose end user price is regulated. 1.36 ERB's record in regulating the lODs has been spotty. Until about 1990, ERB was generally slow in rendering decisions, and it tended to avoid adjudicating fundamental issues. In 1991, the term of the ERB Commissioners was fixed at five years, and an unusually effective slate of Commissioners was appointed. ERB then began adjudicating substantive issues in its decisions re- garding MERALCO and, subsequently, NPC; also its regulatory inquiry with regard to those two major utilities has been thorough and its decisions were repdered relatively quickly. However, be- cause of human resource and budgetary constraints, it continued having difficulty with applying the regulatory process in a timely manner to the other lODs. 1.37 Until 1990, NEA interpreted its mandate as both setting coop tariffs and then regu- lating the result. The rate formula NEA was applying was too stringent and its processes too cum- bersome, thereby limiting its effectiveness as a regulator. In late 1990, NEA redefined its role; it would articulate a tariff policy to the coops, and let them set their own rates. Then, it streamlined its regulatory processes, placing the onus on each coop to provide evidence that it had consulted with key groups within the community regarding the proposed adjustments. NEA continued to hold rate hearings locally, but only after the views of all parties had been formulated. In this way, NEA regu- lated tariff adjustments for more than 100 coops over a period of less than fifteen months. During that span, virtually every coop increased its rates by about 30 - 50%; and, yet, the coops faced only minor political opposition to these increases. 1.38 Shortly after the first round of adjustments under this new system, regulating the coops was shifted from NEA to ERB. Both organizations acknowledged that ERB was understaffed and had - 11 - insufficient budgetary resources to absorb its new regulatory responsibilities, so they jointly peti- tioned the Department of Budget and Management (DBM) to enable the transfer of NEA's regulatory staff and budget in their entirety to ERB; this was not considered feasible under existing law. During 1993, ERB asked NEA to continue doing the detailed work related to the regulatory process on a consultancy basis; at best, this arrangement can serve temporarily. So, now ERB has the responsi- bility for regulating 135 utilities with resources that were barely adequate for fifteen of them. 1.39 As the role of private development of power facilities increases, so too will the impor- tance of regulation. The private developers are depending on regulation to ensure that the system provides no unfair advantages. The consumers are depending on regulation to protect their interests with regard to cost and quality of service. Yet, ERB has some serious capacity constraints, and its ability to fulfill its projected role will depend on the Government making available some significant opportunities for institution building. E. Conclusions 1.40 From current realities, the foregoing paragraphs lay out constraints the structural framework will need to accommodate and issues the power sector will need to address. Additional constraints will arise from the shift in balance between the private and public sectors as a result of the spate of privately developed investments in generation that are expected during the next ten years. These will be analyzed and discussed in Chapter 2. Still other constraints will emerge from the financial impacts of adding new participants who are expected to add efficiency and reliability to the sector, but who will also expect an appropriate return as a commensurate reward. These con- straints and issues are the subject of Chapter 3. Chapter 4 will consider the effectiveness of on-going private development in power. It will consider the lessons from the current crop of IPPs as well as the need to improve the effectiveness of the distribution utilities. Together, these chapters cover constraints that must be factored into any recommended structural framework for the sector. 1.41 Chapter 5 considers (i) the parameters for unbundling NPC, and (ii) the proposed structural framework for the sector. The objectives of reorganizing NPC are to enable the proper incentives for functions that should be kept national in scope, while enhancing the manageability and efficiency of functions that can be decentralized. Because of the breadth of constraints emanating from current realities, structural models that have been tried in other countries are unlikely to work in the Philippine context. The structural framework being recommended was designed specially for the Philippines and includes features from the full range of privatization models being implemented elsewhere. The benefits of recommending a structural framework for the post privatization period will be limited unless combined with an analysis of the adjustments needed to make it work. Some of that analysis will be provided in earlier chapters, in relation to very specific issues. Chapter 6 will address improvements to the enabling environment for private development of power in the Philip- pines, especially the legal framework, electricity pricing, and the disposition of NPC's directly con- nected industrial consumers through wheeling. Chapter 7 will consider the role of regulation during the privatization period and after the first wave has been completed. In that context, it will examine ERB's approach to regulation, its key processes and its institutional capabilities. 2. Power Demand and Supply A. Introduction 2.1 NPC expects Philippine power generation capacity to increase 250% between 1990 and the year 2000, from 23 TWh to 59 TWh. This chapter assesses the expected demand for this in- creased power in the Philippines during the period, including long-range planning and technical op- tions for the turn of the century. (Sector investments and financing to meet that demand are dis- cussed in Chapter 3.) Fnally, because power must be transmitted and distributed effectively, the chapter also prsents analyses of the technical and investment rquirements of these subsectors. B. Power Demand and Supply to 1998 Energy and Demand Growth Estimates 2.2 The key determinant for estimating future sector investment requirements is the de- mand forecast. In the Philippines this needs to take into account: (a) overall economic growth; (b) differential regional development; (c) demand side management measures; (d) industrial growth; (e) distribution utilities' sales and technical efficiency forecasts; (f) income and price elasticities, and (g) the self-generation capacity resulting from gensets imported during recent power outages. The domi- nant factor in load growth will likely continue to be oveall growth of the economy. There is always uncertainty in medium and long-range growth forecasts, and so both high and low growth scenarios and annual updates are needed to optimize the investment program. For the medium term, NPC must also develop a realistic "base load" scenario which is in line with the contracts for power supply it is currently signing with the distribution utilities. 2.3 The methodology for NPC's Power Development Plan (PDP) includes analysis of grid- specific industrial and commercial activities, demand trends, price and income elasticities, and re- gional and total GDP growth forecasts. Demand estimates from the distribution utilities and NPC's regional managers also play a part. However, many of these analyses have been mooted by the supply shortages which interrupted discernable trends, stimulated off-the-grid self-generation by consumers, and left analysts uncertain of how power demand would grow now that supplies have been restored. Assuming that power demand is restored to a predictable fraction of total economic activity, the main and by far most important variable in the demand projections is GDP growth, which must follow the tarrets set by NEDA. Constrained to use the GDP target as the basis for its own forecasts, NPC pegs its estimate of the demand elasticity for electricity at between 1.25 and 1.5 times targeted GDP growth. 2.4 NEDA GDP annual growth targets to the end of the decade average about 8%1', much larger than recent 2% annual historical performance of the Philippine economy during the previous decade, but smaller than sustained growth rates for the regions served by the Mindinao and Visayas grids during the 1981-1991 decade. In NPC's 1994 PDP, this level of economic growth tanslates into electricity demand growth forecasts of about 12% p.a. between 1994-2000. The Bank's GDP growth forecast is lower, about 5.5% per annum, with electricity sales increasing at about 9.5% p.a. I/ NEDA's fortcast for GDP growth ran for the 1994 is now 3%4% (reduced from 6.7%) un is 7.7%, l.2%, 3.8% iN 10% for 195-98. - 13 - (and 8.7% in Luzon). Taking the Bank's lower estimate as a baseline and NPC's 1994 forecast as a high scenario, the tw total power demand estimates diverge by 10% by 1998 and 17% in the year 2000. Nevertheless, both growth pwjections are reasonable, being in line with those experienced by other Asian countries, particularly those with low per capita electricity consumption (Philippine con- sumption was 408 kWh/person during 1993). PHILIPPINES ENERGY SALES UAE C.2 so 40 0~~~2 1990 19*5 1990 1b95 2000 l l0 Figure 2.1 2.5 Ile base demand scenario is presented in Table ,2.1, and assumes a GDP elasticity ratio of 1.3 for Luzon (as used by NPC) and slightly higher elasticities for Visayas and Mindanao. Under this forecast, energy sales for Luzon in 1998 will be 29.5 Tlwh, about 40% higher than the 21.1 TWh sales in 1994 (Table 2.1). Overall, total power sales are expected to increase 44%, from 28.7 TWh to 41.4 TWh. (Annex I details the forecasting assumptions and analyses for each of the three main grids.) MERALCO's Forecast 2.6 MERALCO supplies 2.1 million consumers, accounting for about 70%e of demand in Luzon and about 60% of demand in the country as a whole. MEERALCO's own forecast, based on trend analysis of the domestic, commercial and industrial consumer is the basis for its USS800 mil- lion program for distribution investments during 1994-98. MEERALCO assumes industrial sales will grw rapidly and increase its sbare of the total fiom 36% at present to 50% by 2010, with a smaller grwth and a corresponding reduction of the sbare of commercial and domestic consumers. MERALC incorporates in its forecast expected loss reductions, from 14% in 1993 to 10% by - 14 - 1998. These changes, along with DSM, are expected to increase MERALCO's load factor from 65% to 72%. Overall, MERALCO's sales forecast (Table 2.2), supported by appropriate investment, is one third lower than NPC's demand forecast (and slightly lower than the Bank's). Table 2.1 - Baseline Power Demand Forecast Year LUZON VISAYAS MINDANAO TOTAL Sales Gene- Peak Sales Gene- Pealk Sales Gene- Peak Sales Gene- Peak 1000 rtion D- 1000 ration De- 1000 ration Dc- 1000 ration De- GWh 1000 mand GWh 1000 mand GWh 1000 mand GWh 1000 mand GWh MW GWh MW GWh MW GWh MW 1990 17.64 19.10 3023 1.87 2.05 494 3.73 3.96 621 22.9 24.7 3974 1992 18.88 20.37 3250 2.25 2.49 622 4.24 4.46 725 23.8 25.6 4186 1994 21.13 22.84 3693 2.S8 3.20 705 4.70 4.97 Sl1 28.7 30.8 4937 1996 24.73 26.73 4286 3.52 3.91 851 6.00 6.38 1038 33.9 36.3 5830 1998 29.50 31.89 5128 4.26 4.63 1010 7.66 8.15 1329 40.4 43.2 6858 2000 35.20 38.05 6102 5.15 5.60 1201 9.52 10.13 1648 48.1 51.53 8262 Increases in Generation Capacity: IPPs, Independents, and Gensets 2.7 Most of the initial growth in NPC's generation capacity since the onset of the crisis has come from IPP installation and operation of solid, quickly-constructed plants with relatively low fuel- conversion efficiency. These plants will revert to peak demand once adequate base load capacity is available in 1995. An estimate of the reliable capacity for Luzon incorporates just such assumptions into an operating model in which the output of existing and expected plants is available according to contracts, engineering specifications, maintenance and repair schedules, age-derating, and reasonable assumptions of seasonal and annual effects on hydro generation. To forecast power supply well, it is necessary to predict accurately the completion of new plants and transmission lines. This is difficult for the IPPs, which even after contract award are subject to vagaries of equity and loan financing.Y Capacity increments can also be delayed when projects suffer delays due to environmental or com- munity acceptance problems (as happened with the Masinloc and Calaca I1 coal plants). Table 2.3 shows estimates of Luzon's dependable power capacity, including all contracts signed with NPC. 2.8 Another source of supply--and of supply uncertainty--are the several prospective con- tracts between IPPs and distribution utilities and industrial users. Official intelligence about the progress of these deals remains incomplete, notwithstanding their potential impact on total supply and demand. 2.9 There are also numerous self-generation projects at factories, industrial estates, and even large commercial enterprises. Some 1600 MW of genset capacity is known to have been im- ported for back-up generation during the crisis. Here the uncertainty is over how much, how often, ai h is precaiey fiom such financing difficulties that severml signed and accredited BOT contcts hav recentdy been cancelled wben perfonmance contmcu could not be signed. - 15 - Table 2.2 - MERALCO's Energy Sales Growth Forecast (annual growth rates) Period Residenial Commercial Industrial Total 1987-1991 4.90 7.70 11.30 7.90 1992-1995 4.30 3.10 5.00 4.10 1996-2000 8.50 8.80 11.70 9.80 and under what circumstanCeS (fuel cost changes, power outages, demand charges, peak-period pricing, etc.) this already installed but off-the-books self-generation capacity will be utilized after grid supplies are fully restored. For forecasting purposes, gensets are assumed to operate at a 10% duty cycle during the remainder of the decade. 2.10 These supply uncertainties pose a serious problem for the Philippines. There would be substantial general economic losses from a repetition of supply shortages if the expected capacity does not materialize. On the other hand, duplication of capacity would be costly for the sector and will have diverted needed capital from other investments. As self-generation capacity is already in place, its use must be tolerated, but it should be studied and monitored in order to improve local grid-demand forecasts. To minimize the backlog of uncertain projects and the supply risk the public assumes while they are pending, DOE accreditation should include definite and clear expiration dates, after which projects would be subject to reaccreditation (para. 6.27). PNwer Generation, peak Demand, and Reserve Capacity 2.11 Total energy losses within the NPC system are about 7%, split about equally between transmission and in-plant use. There are greater opportunities for loss reduction within the distribu- tion subsector, and MERALCO and the coops are making additional efforts and investments to take advantage of them. N 2.12 Capacity expansion is not only needed to meet recently unmet and new demand, but also to (i) replace obsolete and worn-out capacity; (ii) restore technologically inappropriate peaking cycle plants pressed into base-loading mode during the crisis to economic peaking operation; (iii) replace base-loaded plants fired with expensive oil with coal-fired substitutes; and (iv) replenish r- serve capacity. 2.13 For the Philippines, a substantial reserve would be a prudent hedge against several risks: (i) a temporary preponderance of old, unreliable, and probably short-lived thermal plants; (ii) oil-intensive new capacity, vulnerable to sharp increases in oil prices even at lower load factors; (iii) uncertain results of the rehabilitation of some large plants, which may continue to be undependable; (iv) vulnerability of hydro plants to recurrence of severe droughts such as those of 1991-92; (v) pow- er transmission limitations between grids and even within them; and (vi) project delays due to NPC's slow procurement, contractor failure, and regulatory obstructions. - 16 - PEAK LOAD AND CAPACITY IN LUZON l0 r~~~~ ECAVALCXTY-bg L VZJ X 1310% IUd- V=UC 130*A PR VD-bo Figure 2.2 2.14 Based on NPC's investment programs for projects already committed or under imyle- mentation, and a risk approach to the likelibood that individual IPPs with the distribution utilities will be brought to fruition, the dependable capacity for the LAizon grid is expected to gmvw as shown in Table 2.3. This table includes: (i) plants being built by IPPs under PPAs with NPC; (ii) a modest amount of capacity that NPC is committed to develop with unilateral or bilateral financing; and (iii) and plants developed by IPPs under direct contracts with MIERALCO. Details for each of the exist- ing and planned plants entering into operation are given in Annex 1. Some old plants are also as- sumed to be retired by 1998 (Manila 200 MW and Sucat 350 MW) but each case will require a cost/benefit analysis before closing the plant. Tle analysis of supply and demand (Figume 2.2) indi- cates that power outages would end during 1994, and NPC would have ample reserve capacity by 1997-98. 2.15 Under the base case, total mserve capacity by 1998 would be about 2,700 MW (about half of baseline forecast peak demand, Figume 2.2). Total reserve would be adequate even if high demand growth materializes, assuming that capacity additions are not unexpectedly delayed. lb me duce the riskes from such timing failures, the Govermment should adopt the following measures: (i) it should update the PDP annually; (a) it sbould not sign additional take-or-pay contracts; (i) it should exercise, special scrutiny before extending or renewing accreditation of contracts which are not effec- tive by the expiration of initial accreditation periods (para. 6.28); and (ii) NPC should consider postponing by 1-2 years projects with contracts whicb arc not yet effective. ---------------- - 17 - C From Prescriptive to Strategic Planning 2.16 Given the power sector's large investments and its influence over other sectors, a sound power investment strategy and comprehensive power plan are needed for the country's eco- nomic success. However, this is a complex task, particularly challenging because of fully joint par- ticipation of the public and private sectors. Power planning with sophisticated computer programs (e.g WASP) has previously been used to formulate least-cost expansion plans; but now it may be inadequate for the Philippines because: (i) the approach is essentially deterministic, and may not capture risks and uncertainty, such as abrupt changes in energy prices or disruptions in economic growth; (ii) most models only minimize financial costs, but offer less help in choosing among solu- tions when multiple objectives are to be optimized (eg. environmental quality, financial viability, and macroeconomic impact); and (iii) as private participation in the power sector increases, many deci- sions which formerly fell in the realm of planning are now better left to a competitive market. Table 2.3 - Sources of Dependable Power Capacity in Luzon .190 1991 19 93 1994 1995 1996 1997 1996 1999 200 Oil 1523 1555 1465 809 1204 1495 1466 1437 1408 1013 744 Diesel and CC 0 0 0 157 911 1164 1161 1157 1137 806 757 Hydro 1119 1035 648 518 813 838 853 903 953 1298 1296 Geothermal 559 561 571 547 775 860 852 867 1139 1386 1375 Coal 116 245 245 250 246 381 1167 1376 1662 2792 3971 Gas 0 420 401 520 673 670 667 663 660 657 654 TOTAL THROUGH NPC 3317 3816 3329 2800 4621 5408 6165 6404 6959 7952 8797 SUPPLIES CONTRACTED 0 0 0 0 141 303 746 1077 1140 1142 1140 BY MERALCO TOTAL CAPACITY (04W) 3317 3816 3329 2800 4762 5711 6911 7480 8098 9094 9936 This include prirmarily supplies being developed by IPPa under PPAs with NPC, which NPC will resell to drtributors; end modest amounts of gene tion that NPC is already cornmitted to dwvelop. 2.17 The emergent mix of public and private power generation requires a gradual move from fully prescriptive to indicative planning; and a strategic approach incorporating risk and multi- ple objectives. Until sales and prices are fully determined by the market, power planning will contin- ue to be needed to ensure optimal development of the sector, and to protect consumers from risks stemming from market imperfections. The main concern is an unbalanced expansion, including ca- pacity shortages or surpluses, or an inappropriate fuel mix. Planning should therefore include: (a) Reduced emphasis on the assessment of specific projects, and greater focus on the soundness of the overall expansion and the flexibility and robustness of the plan, (i.e. its ability to perform well under various scenarios.) (b) Incorporation of risk and uncertainty associated with different technologies (eg. fuel, foreign expenditures and capital costs) and different institutional arrangements. (c) Incorporation of multiple objectives (eg. environment, use of local energy resources, self-reliance, multipurpose use of water resources, etc.). - 18 - 2.18 Particularly important would be that the overall planning takes national rather than individual company concerns into consideration, for example for fuel choices. Responsibility for overall planning sbould be transferred from NPC to DOE. NPC's expertise cannot be gainsaid, however, and collaboration will be needed until DOE develops its own expertise (para. 2.45). This would require training and the introduction of the Trade-off/Risk planning, as used by USA power utilities to address risk and multi-objective issues. 2.19 DOE should also improve its monitoring of new and pending contractually obligated power generation and capacity. The authorization given to the utilities to generate their own power or contract it with IPPs is now bringing additional uncertainty to NPC's forecast (pan 2.8). Therefore, DOE, which is responsible for accrediting these contraets, should now assume responsi- bility for planning, which can be enhanced by requiring (i) the utilities to sign long-term supply contracts; and (ii) NPC to comply and compensate its consumers for demand shortages or excessive capacity. The mixture of public and private supply substantially complicates power dispatch and re- quires a cooperative relationship between NPC, the distribution companies and the IPPs. Accreditation 2.20 Executive Order 215 mandates that DOE accredit independent power agreements so that PPAs are 'consistent with the development plans formulated by the National Power Corpora- tion;" and thereby ensure consistent sector development and reduce risks to consumers and the econ- omy. Regulations set several economic desideraza for accreditation: (i) Greater efficiency or lower cost generation than from existing plants, (ie. an avoided cost approach); (ii) use of indigenous and/or renewable resources; and (iii) access to lower costs of capital or cheaper plant investment. 2.21 These criteria are sound, but they were largely ignored during the power crisis. Mor- eover, the methodologies to implement these criteria have not been defined; nor have the tradooffs between the Government's and NPC's assumption of market risk, and the IPPs' protection by take- or-pay contracts. DOE's accreditation should require (i) better analysis of an adequate demand-sup- ply balance, (ii) clear criteria for the application of the avoided cost, and (iii) a fuel mix strategy. Each new accredited development should also fit into a general system plan, specify appropriate technology, and include a solid financing plan. Finally, the accreditation should set a realistic but final expiration date within which the final IPP contract should be signed, and include substantial performance guarantees. Table 2.4 Power Sector Investment D. Power Sector Investment (US$/kW Demand) in Philippines and Indonesia (1994-98) 2.22 The investments and capacities required until 1999 are now Investment Philippines Indonesia well defined, and should result in adequate peak capacity and reserves Generation 1877 1774 even under a high demand scenario. Transmission 581 417 Philippine Government-controlled in- Distribution 381 1003 vestments in power generation and transmission are comparable to those Total Sector 2840 3194 of Indonesia, an archipelago with similar characteristics (Table 2.4). However, private sector investments in distribution in the Philippines are clearly low at just 13% of the total sector investment and may become a major constraint for power development. By contrast, - 19 - Indonesia plans to invest nearly one third of its total on distribution, targeting expanded rural elec- trification and reduction of distribution losses to below 12%, about half the level in the Philippines. 2.23 Philippine long-term sector power sector investment (including all generation, transmis- sion, and distribution requirements) is estimated at US$25-38 billion for 1994-2004, depending on the demand forecast (12,000-17,000 MW by 2004).3' Specific strategic recommendations for addi- tional investments will be the subject of a Master Plan Study to be prepared with support from ADB and incorporated in annual PDPs. The Government's overall policies for managing risks and benefits of available fuel options will define important parameters of sound investment plans for the sectors by: (a) optimizing the use of indigenous resources (geothermal, gas and coal), and reducing depen- dence on fuel imports; (b) improving thermal generation through rehabilitation; (c) creating a better strategy for hydro development; (d) linking and effectively managing a national grid; and (e) main- taining network soundness and lowering distribution losses. These goals are consistent with the Government's targeted fuel mix for power production shown in Table 2.5. Generation Investment 2.24 Following NPC's Board decision to offer to the private sector all new power genera- tion except multipurpose hydro, 80% of additional capacity approved for 1993-98 will be built under BOT/BTO contracts. New and recent private sector generation must be integrated with existing and rehabilitated NPC capacity to ensure: (a) a suitable mix of fuels for base, intermediate and peak load; (b) spinning reserve and backup reserve capacity to cover forced outages and scheduled main- tenance situations; (c) adequate reserves in case of unusual droughts; and (d) ample transmission capacity over NPC's lines. Appropriate technology for these purposes will include: hydro with pump storage, gas turbines and diesel for peak capacity; oil fired and combined cycle plants for intermedi- ary cycle; and geothermal and coal plants for base load. Spinning reserve capacity will be provided by normally operating coal plants at 95% of their capacity. Although specific plants are not normally designated for reserve duty, as less costly production comes on line, recently installed crisis-stem- ming but fuel-intensive plants may revert to reserve usage. Thermal Plants 2.25 Thermal generation will include: (a) coal fired power plants, which constitute the least- cost solution for power generation in the Philippines; (b) rehabilitation of NPC's existing power plants; (c) geotbermal energy; (d) combined cycle plants; and (e) peak plants (diesel and gas tur- bines, which in the Philippines use a mixture of 30% bunker and 70% fuel oil.) These investment opportunities are discussed in the following paragraphs. 2.26 Existing Plants NPC's existing thermal plant totals 2,225 MW, comprising four stations in Luzon (1,775 MW), six in Visayas (205 MW), and five in Mindanao (237 MW) (including three Power Barges). Luzon thermal plants' average 23 years of age and require rehabilitation. Their performance has deteriorated over the last 5 years (Table 2.6), and thermal efficiencies of some have / Estimates of the ten year investment requirements for the Philippines power sector can be can be obtained (a) for generation and transrnieion from NPC's 1993 detailed Power Development Plan (PDP 1993) covering requirments to 2005 am (b) for distribution by extrmpolaLing IAERALCO's five year plan prorasa with load growth, aggregated together with a ariilar pat- tern of reinformement and expansion in proportion to their respective demands for the 15 IODN, and the 1131 coops. 4/ Malaye 1&2, Manilb I&2, Sucat 1-4, and Bataan I&2. - 20 - fallen from a design value of 33% to about 25%. Other plants show availabil- Table 2.5 Fuel Mix Targets 1994-2004 ity of about 70% compared to an indus- try average of about 85%. About 94 98 2004 US$300 million has been invested in rehabilitation since 1986, and five more Hydro 16% 11% 25% units with a total capacity of 1,400 MW Geothermal 25% 35% 25% are being considered for rehabilitation. Coal 8% 31% 25% Rehabilitation of Sucat 1 & 2 was not Oil 51% 23% 25% successful. Work on Sucat 2 and 4 will be completed in 1994. Old thermal plants Total 100% 100% 100% can be commercially viable for 15 years following rehabilitating, but they will in- creasingly be dispatched to meet peak demand, as more efficient and cheaply-operated plants replace them for base load operation after 1997. These plants are a valuable resource and should not be retired without detailed justification. NPC is considering Rehabilitate Operate Lease (ROL) or man- agement contracts with private sector operators for Malaya and Calaca, on the ROL model used for Ambuklao and Binga hydro and Nap coal. 2.27 Nuclear Plant The future of the nuclear plant is uncertain, due to opposition to nuclear development, concerns about the safety of the installation, and the progressive obsolescence of the non-nuclear components. The Government should therefore make best feasible use of the existing site and equipment by completing a study on optimal conversion of the plant or redevelopment of the site. 2.28 Gas Gas is the preferred fuel choice for thermal power generation. In is an inexpensive fuel, requires relatively inexpensive, operationally flexible and quickly installed plants, and generates fewer environmental problems than other fuel alternatives. Therefore, the Government should accel- erate exploration of the Palawan field, and give priority to constructing the needed US$1.5 billion pipeline from the field to Bataan. This pipeline could be largely justified by the benefits to power projects,(eg. the cost savings from retrofitting gas turbines from fueling with imported high-sulphur Bunker-C to combined cycle operation.) Considerable benefits of gas field development to industrial and commercial customers are possible as well. Nonetheless, this approach needs time to develop, and is not likely to yield new gas-fired generation before 1998-2000. 2.29 Coal Coal is the cheapest fuel for power plants in the Philippines, and the prospects are for stable prices and ample world-wide supply. However, problems with Calaca I have engendered widespread opposition to that and other coal-fired plants, and there have been delays in gaining envi- ronmental approvals. Properly operated, low-sulphur fired plants would not interact with torrential downpours to create acid-rain. In the medium term, flue-gas scrubbers can be used to address local environmental impacts of the coal with higher sulfur content. Most larger plants being implemented by IPPs to supply NPC and MERALCO are expected to be fueled by coal. Geothermal Development 2.30 In comparison with other countries with equivalent geothermal resources, the Philip- pines has been quick to develop geothermal generation capacity to about 800 MW today. With com- pletion of the 640 MW Leyte projects in 1998, the country will make greater use of geothermal - 21 - Table 2.6 - Performance of NPC Thermal Plants Station Age Capatity Rating Effy Avail Rehabilitation Years MW MW % % Year USSm Malaya 1 18 300 218 29 67 1987 36 Malaya 2 14 350 229 32 87 1986 12 Sucat 1 25 150 139 33 91 1989 91 Sucat 2 23 200 158 29 83 Sucat 3 22 300 140 25 89 1993 95 Sucat 4 21 300 233 30 70 1990 92 Manila 1 28 100 95 32 95 Manila 2 27 100 95 31 90 BPPT 1 21 75 68 32 89 BPPT 2 9 150 88 29 35 1994 30 Batangas 9 300 244 32 77 Calaca 32 77 Totals 2325 1707 356 Note: excludes 3 recent Mindanao power barges energy than any other in the world.!' 2.31 Earlier geothermal developments were carried out by PNOC and NPC; the former responsible for steam exploration, and the latter for power generation. The recent Bank-financed Leyte projects represent a promising new model for the near term, with PNOC bearing the same responsibilities for generation and delivery of power to NPC's bulk power transmission substation as do BOT operators of conventional thermal plants. This approach provides PNOC with an opportunity to minimize costs of production, and maximize the potential of the resource. To these ends, IPPs with three separate BOT contracts will generate the power for PNOC, while the latter will retain control over the steam collection and the electric power subtransmission system. PNOC retains grea- ter control over its investment in production drilling: weliheadc, steam field and power plant mainte- nance, and its operations in arranging backup capability in the event of forced outages. 2.32 Tapping other geothermal resources will prove more difficult. Estimated at more than 2,000 MW, they are remote from load centers and are risky, being subject to unexpected steam-field failures. Private exploration of geothermal resources has been inhibited by excessive royalties and taxes, which reduce financial returns to around 10% in the event of success. This return is too low to warrant private investment in exploration and development in the event of success, let alone offset the risk of failure. A temporary exception on royalties has been given to PNOC (as a Government corporation), but such exceptions must be made more permanent or royalties themselves permanently lowered on an economic basis if geothermal development, notwithstanding environmental advantages, I/ Additional powntial exists in: (i) Mindanso (Mt Apo (240 MW), Mt Pointer (OOlMW); CU) Viuyas (Leyte 750 MW, Leyte B 400 MW, Nego existing 112+X0 MW, Mambukal (100 MW); and Ctii) LAzon (Bacman (I50 MW), Tiwi (330 MW), B aCan new 330 MW), Batun Buhai (IOOMW), Pinsubo (100 MW), and Macben (20 MW) - 22 - is to become and remain financially attractive to the private sector and PNOC, respectively. The Government is promoting as a Presidential priority a geothermal bill to eliminate royalties for the first 15 years of the Leyte project, and this can be a model for future royalty treatment. Hydro Power Development 2.33 Philippines hydro resources are estimated at about 10,000 MW. Hydro development advantages include (i) the use of local resources (and lower import requirements), (ii) renewability, (iii) potential for multipurpose development (irrigation, water supply), and (iv) efficient dispatch in standby and spinning reserve settings. But the cycle of deforestation-erosion-reservoir siltation on the one hand, and unpredictable and extended droughts on the other, has resulted in substantially reduced hydro output. And even now that there is breathing room for fuller consideration of slower-to-devel- op hydro generation, examples elsewhere in the world are discouraging. Environmental and resettle- ment issues have substantially slowed down or paralyzed hydro development in many countries, and the project-cycle required for large dams may be as long as ten years. 2.34 Large hydro projects are likely to remain in the hands of the Government, where they have until recently languished in the feasibility stage. (A single project completed 8 years ago has been the only hydro project constructed in the last 12 years.) Some of the problems impeding de- velopment are specific to the Philippines; others are common to hydr projects everywhere. They include (i) water supply related project risks; (ii) the need for long-term (5+ year) construction loans; (iii) the long period required to amortize the investment; (iv) high local content of construction expenditures (and limited capacity for export financing); (v) difficulties in securing and expropriating land; (vi) the need to optimize total water resources; (vii) paramilitary threats in remote areas where most hydros are located (now substantially improved); (viii) absence of large capacity transmission lines (particularly for northern Luzon); (ix) cost-allocation disputes over the marginal and average cost to each hydro project of installing lines to serve multiple hydros; (x) bias of power planning tools such as the WASP program against hydro projects (because the analysis is ended after ten years, and the only benefit assumed for the remaining forty years is the unamortized cost at that time); (xi) political and environmental opposition to hydro development; (xii) requirements for con- sultation and approval from multiple agencies, consistent with hydro's multi-sector impacts; and (xiii) a previous lack of financing to complete the costly project designs and needed comprehensive envirnnmental assessment which would meet these numerous obstacles. 2.35 NPC has identified 1 I schemes for development of detailed designs, with an aggregate capacity of about 2,500 MW, six in Northern Luzon and five in Mindanao (Table 2.8). In addition to large hydro plants, there are some 37 "small" 20-50 MW hydro projects (mainly run-of-river), totalling 900 MW, for which feasibility studies have been completed. These projects (Table 2.8) may be offered as BOT prjects to the private sector by the end of 1994. The average cost of the 80 schemes is about US$1400tkW, and if their cost can be amortized over 25 years their energy costs are quite reasonable, ranging between R0.85-1.85/kWh. But running transmission lines to their remote locations may make their total costs much higher. To encourage proposal development, NPC has specified a system of peak and off-peak pricing in the bidding specifications, which reduces the hydrology risk and compensates for storage characteristics. NPC has assumed responsibility for these projects, but the Government has indicated that financing the larger projects is apt to present prb- lems. Nevertheless, some of them could be of interest to distribution utilities or larger industries if transmission facilities and wheeling arrangements could be provided. Hydros too large for existing distributors would be feasible for the consolidated distribution companies recommended elsewhere in this report (para. 5.16). - 23 - Table 2.7 Hydro Potential (MW) in the Philippines Status Luzon Visayas Mindanao Total Existing 1226 2 986 2214 Pre-feasibility 5083 339 1327 6749 Feasibility 2510 279 1314 4103 Definite Design 1281 20 0 1301 Total 10100 640 3627 11437 Table 2.8 Hydro Projects in Advanced Design/Feasibility Stages Project Instaled Annual Construction InstaLed Energy Capacity Energy Cost(1988) Cost Production MW GWh US$m USSlkW VIKWh Luzon Location Kalayan #3,4 300 665 270 900 0.92 San Roque (North) 390 1214 550 1410 0.98 Agbulu (North) 220 712 343 1560 1.09 Binongan (North) 175 718 485 2711 1.53 Matuno (Center) 180 528 364 2022 1.56 Casecnan (Center) 270 1397 1080 4000 1.75 Mlndanao Location Agus III 225 1085 381 1690 0.81 Tagaloan II 62 374 139 2241 0.84 Pulangi III 90 282 162 1800 0.96 Bulanog Baton 222 876 379 1707 0.98 Pulangi V 350 1310 775 2214 1.34 Total 244 9161 4928 Transmission and Distribution Investment 2.36 NPC's 230/138/69kV transmission systems can be considered as two principal ele- ments: (i) the bulk power or "backbone" system interconnecting the major generating stations with the substations serving the major load centers; and (ii) the radial sub-transmission lines feeding out from bulk supply substations to the rural load centers. In Luzon, the backbone system operates at 230 kV. In Visayas and Mindanao, the backbone systems operates at 138kV. Although the present backbone system is quite extensive, its power transfer capacity is limited by the relatively low volt- ages and th-. lack of interconnections between adjacent transmission lines, dictated by the rugged mountainous terrain. Transmission limitations keep thermal generating plants from being cited at remote locations which otherwise enjoy advantages of port access for fuel supplies, ample cooling water, and more easily met environmental constraints. Transmission limitations also precludes devel- opment of the substantial hydro resource already in place, particularly in Northern Luzon. - 24 - Table 2.9 - Capacities and Current Service Near Promising Small Hydros Location Utilities Hydro Sites % Cost No Sales LF No Generation sales (S/kW) (GWh) (MW) (GWh) Palawan 1 2.9 40% 2 64 227 - 1000 Mindoro 2 2.9 40% 5 87 257 - 1236 Negros 5 441 55% 2 61 285 65% 1352 Cagayan De Oro 11 2118 52% 5 72 290 15% 1371 Northern Luzon 13 885 55% 15 498 1663 - 1385 General Santos 10 920 59% 6 113 364 48% 1539 Panay 7 340 54% 2 19 63 26% 2370 Total 49 4709 37 914 3149 2.37 By 1998 interconnections at 500 kV within Luzon, 380 kV HCDC (800 MW HVDC) between Leyte and Luzon, and 230/138kV (200 MW) within Visayas, will reduce transmission losses and facilitate efficient intra-regional exchange of energy between generating plants and load centers. In addition, a 400 MW link between Leyte and Mindanao has been planned for the year 2000. More will still be needed, including reinforcement of existing networks and the provision of system stabilization and compensation facilities to ensure proper operation during peak and low-load conditions.
Groupe de la Banque mondiale · Pre-2003 Economic or Sector Report
Philippines - Power sector study : structural framework for the power sector
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