CHALLENGES IN PRICING ELECTRIC POWER SERVICES IN SELECTED ASEAN COUNTRIES

Transcription

1 CHALLENGES IN PRICING ELECTRIC POWER SERVICES IN SELECTED ASEAN COUNTRIES PHILIPPINES CLIMATE CHANGE AND CLEAN ENERGY PROJECT (C ENERGY) FINAL REPORT APRIL 2013 This report was produced for review by the United States Agency for International Development (USAID). It was prepared by the Center for the Advancement of Trade Integration and Facilitation (CATIF), Inc. for the International Resources Group (IRG).

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3 Challenges in Pricing Electric Power Services in Selected ASEAN Countries PHILIPPINES CLIMATE CHANGE AND CLEAN ENERGY PROJECT (C ENERGY) FINAL REPORT April 2013 DISCLAIMER The author s views expressed in this publication do not necessarily reflect the views of the United States Agency for International Development or the United States Government

4 Contents List of Tables... iv List of Figures... vii List of Acronyms of Philippine Distribution Utilities... viii List of Other Acronyms... xi Executive Summary... xiv I. Background Motivation Objectives and Scope Model Cases Structure of the Report... 5 II. The Philippine Electricity Market Market Structure Generation Transmission Distribution Supply Regulatory Regime The Electric Power Industry Reform Act Generation Transmission Distribution Supply Regulation Structure of Philippine Electricity Prices Price Components Tariff Schedules of Selected DUs Trends in Philippine Electricity Tariffs Representative Philippine Electricity Prices Composite Price Base Composite Price Pre-tax Base Composite Price Impact of MERALCO on Composite Price Key Issues Affecting Philippine Electricity Prices Wholesale Electricity Spot Market Pricing of Bilateral Contracts i

5 6.3 Incentives for Indigenous Fuel III. Structure of Electricity Markets in Other ASEAN Economies Indonesia Market Structure Recent Performance Malaysia Market Structure Sector Performance Thailand Market Structure Regulatory Regime Progress and Challenges in Regulation Singapore Current Market Structure Comparison of Philippine and Singapore Wholesale Electricity Market IV. Electricity Prices in Other ASEAN Countries Indonesia Price Structure and Regulation Computation of Tariffs Malaysia Price Structure and Regulation Computation of Tariffs Singapore Price Structure and Regulation Computation of Tariffs Thailand Price Structure and Regulation Computation of Tariffs V. Benchmarking of Philippine Electricity Tariffs Impact of Taxes Impact of Subsidies Impact of Price Differences Synthesis VI. Policy Simulations Components of Base Composite Price Restructuring Taxes Zero VAT Six-percent VAT Almost Revenue-Neutral VAT ii

6 2.4 Franchise Tax Eliminating Subsidies Lifeline Discounts All subsidies Pricing of Indigenous Fuels Geothermals Natural Gas Changing the Basis of Regulation on Distribution Performance-based Regulation for ECs Asset Revaluation for Computation of Revenue Caps on PIOUs VII. Synthesis and Conclusions Annex I. Customer Classes Used in Model Cases Annex II.1 Composition of Residential Tariff for 200 kwh Monthly Consumption in 2011, by DU Annex II.2 Composition of Commercial Tariff for 3 MWh Monthly Consumption in 2011, by DU Annex II.3 Composition of Low Voltage Industrial Tariff for 50 MWh Monthly Consumption in 2011, by DU Annex II.4 Composition of High Voltage Industrial Tariff for 200 MWh Monthly Consumption in 2011, by DU Annex III.1.1 Policy Simulation Results I for Residential Tariff, by DU Annex III.1.2 Policy Simulation Results II for Residential Tariff, by DU Annex III.2.1 Policy Simulation Results I for Commercial Tariff, by DU Annex III.2.2 Policy Simulation Results II for Commercial Tariff, by DU Annex III.3.1 Policy Simulation Results I for Low Voltage Industrial Tariff, by DU Annex III.3.2 Policy Simulation Results II for Low Voltage Industrial Tariff, by DU Annex III.4.1 Policy Simulation Results I for High Voltage Industrial Tariff, by DU Annex III.4.2 Policy Simulation Results II for High Voltage Industrial Tariff, by DU iii

7 List of Tables Table I.1 Assumptions used in Model Cases... 3 Table I.2 Customer Classes used in Comparing Prices... 4 Table II.1 Installed Generation Capacity in the Philippines by Ownership, Table II.2 Installed Generation Capacity in the Philippines by Grid... 7 Table II.3 Installed Generation Capacity in the Philippines by Fuel Type, Table II.4 Energy Generation: Philippines, Table II.5 Energy Generation by Plant Type and Grid, Table II.6 Number of Distribution Utilities by Grid: Philippines, Table II.7 Electricity Sales and Consumption: Philippines, Table II.8 Components of Residential Electricity Tariffs with 200-kWh Monthly Consumption of Selected DUs, July Table II.9 Components of Commercial Electricity Tariffs with 3-MWh Monthly Consumption of Selected DUs, July Table II.10 Components of Low Voltage Industrial Electricity Tariffs with 50-MWh Monthly Consumption of Selected DUs, July Table II.11 Components of High Voltage Industrial Electricity Tariffs with 200-MWh Monthly Consumption of Selected DUs, July Table II.12 Tariff Components Table II.13 Electricity Tariff for MERALCO Residential Customers with 200-kWh Monthly Consumption Table II.14 Electricity Tariff for MERALCO Commercial Customers with 3-MWh Monthly Consumption Table II.16 Electricity Tariff for MERALCO High Voltage Industrial Customers with 200-MWh Monthly Consumption Table II.17 Profile of Philippine Electricity Tariffs during Table II.18 Representativeness of Computed Composite Prices Table II.19 Composite Prices by Customer Class and Region Table II.20 DUs with Transitory Elements in their Price Schedules in Table II.21 Base Composite Prices by Customer Class and Region Table II.22 Impact of Removing Transitory Elements from Composite Prices Table II.23 Pre-tax Base Composite Prices by Customer Class and Region Table II.24 Percent Decline in Base Composite Prices after Removing All Taxes Table II.25 MERALCO and Composite Prices Table II.26 Regression of Spot Price (ESP) against Excess Supply (EXSUP) Table II.27 Regression of Spot Price on Excess Supply and Peak Demand Table II.28 Elasticity of WESM Spot Price to Excess Supply and Peak Demand Table II.29 Means and Standard Deviations of Generation Prices Table II.30 Salient Features of Selected Bilateral Contracts Table II.31 Incentives Available for the Development of Fossil Fuels Table II.32 Incentives Available for the Development of NRES Table II.33 FIT Rates for Renewable Energy Sources Table III.1 Installed Capacity (MW) and Energy Produced (GWh) in Indonesia, Table III.2 Installed Capacity in Malaysia by Major Power Producers, Table III.3 Electricity Fuel Mix in Malaysia Table III.4 Comparison between Single and Enhanced Single Buyer Models Table III.5 Comparison of Philippine and Singapore Wholesale Electricity Market Table IV.1 Electricity Subsidy in Indonesia, by Customer Category, Table IV.2 Tariff Schedule in Indonesia for Selected Customer Categories Table IV.3 Indonesian Tariffs in 2011 for the Four Model Cases Table IV.4 Regular vs. Prepaid Pre-tax Tariff in Indonesia iv

8 Table IV.5 Tariff Schedule in Malaysia for Selected Customer Categories Table IV.6 Malaysian Tariffs for the Four Model Cases Table IV.7 U-save Rebates to Singapore Households Table IV Tariff Schedule for Selected Non-Contestable Customers in Singapore Table IV.9 Singapore Tariffs for the Four Model Cases Table IV.10 Tariff Schedule in Thailand for Selected Customer Categories Table IV.11 Thailand Tariffs for the Four Model Cases Table IV.12 Effects of Thailand Tariff Restructuring on Consumers Table V.1 Conversion Factors for Local Currency Units Table V.2 IEA Estimates of Electricity Subsidy in Selected ASEAN Economies Table V.3 Comparison of Electricity Tariffs after Removing Taxes Table V.4 Comparison of Electricity Tariffs after Removing Subsidies Table V.5 Comparison of Electricity Tariffs after Adjusting for Price Differences Table VI.1 Some Proposed Legislations to Lower Electricity Tariffs Table VI.2 Composition of Base Component Prices by Customer Class Table VI.3 Base Composite Prices without VAT Table VI.4 Impact of Removing VAT on Base Composite Prices Table VI.5 Base Composite Prices with Six-Percent VAT Substituting All Taxes Table VI.6 Impact on Base Composite Prices of Substituting All Taxes with Six-Percent VAT94 Table VI.7 Base Composite Prices with Almost Revenue-Neutral VAT Replacing All Taxes95 Table VI.8 Impact on Base Composite Prices of Replacing All Taxes with Almost Revenue- Neutral VAT Table VI.9 Base Composite Prices with Franchise Tax Replacing All Taxes Table VI.10 Impact on Base Composite Prices of Substituting All Taxes with Franchise Tax97 Table VI.11 Base Composite Prices After Removing Lifeline Discounts Table VI.12 Impact on Base Composite Price of Removing Lifeline Discounts Table VI.13 Base Composite Prices After Eliminating All Subsidies Table VI.14 Impact on Base Composite Price of Eliminating All Subsidies Table VI.15 Royalties on Natural Gas and Geothermal Table VI.16 Bilateral Contracts on Geothermal Electric Power Table VI.17 Computation of Proportionate Rebate Using Royalties on Geothermal Table VI.18 Base Composite Prices with Proportionte Rebate of Geothermal Royalties Table VI.19 Impact on Base Composite Prices of Proportionate Rebate of Geothermal Royalties Table VI.20 Computation of Additional Rebates to DUs with Forward Geothermal Contracts106 Table VI.21 Base Composite Prices with Additional Rebates to DUs with Forward Geothermal Contracts Table VI.22 Impact on Base Composite Prices of Additional Rebate of Geothermal Royalties to DUs with Forward Geothermal Contracts Table VI.23 Natural Gas Production, Consumption and Trade in Selected ASEAN Countries107 Table VI.24 Possible Distribution of Electricity Rebates Using 2011 Natural Gas Royalty 109 Table VI.25 Base Composite Prices with Rebates from Natural Gas Royalties Table VI.26 Impact on Base Composite Prices of Rebates from Natural Gas Royalties Table VI.27 Regulatory Classification of Electric Cooperatives Table VI.28 Base Composite Prices Post-Completion of ECs Transition to PBR Table VI.29 Changes in Composite Prices of Post Completion of Transition to PBR Table VI.30 Impact on Base Composite Prices of Post-Completion of ECs Transition to PBR117 Table VI.31 Dates of Entry of PIOUs to PBR and Applicable WACC and WCF during the First Regulatory Period Table VI.32 Revaluation of MERALCO s Assets for Regulatory Period July 2007 June Table VI.32 MERALCO s Regulatory Asset Base: Replacement vs. Historical Cost Table VI.33 Depreciation Expenditures under Historical Cost Approach in RAB Table VI.34 Regulatory Asset Base under Historical Cost Approach Table VI.35 Maximum Annual Revenue Requirement under Historical Cost Approach v

9 Table VI.36 MERALCO s Tariffs without Asset Revaluation Table VI.37 Regulatory Impact of No Asset Revaluation in Selected DUs Table VI.38 Impact on Tariffs of Selected DUs without Asset Revaluation Table VII.1 Comparative 2011 Electricity Tariffs after Adjusting for Taxes and Subsidies 125 Table VII.2 Indonesian and Malaysian Subsidy-Adjusted Tariffs Compared to Philippine Tariffs Table VII.3 Potential Policy Changes to Lower MERALCO Tariffs vi

10 List of Figures Figure II.1 Price Variations by Customer Class and Month in Figure II.2 Monthly Spot Market Price: July 2006 December Figure II.3. Spot Price (ESP) vs Excess Supply (EXSUP): WESM, Jun 2006 Dec Figure II.4 Bilateral Contracts Quantity vs Spot Market Quantity Figure II.5 Share in MERALCO s Monthly Generation Charge: Major Energy Sources Figure II.6 ESP and WESMPRICE Figure II.7 Generation Prices of MERALCO s Sources of Energy Figure III.1 Structure of Indonesian Electricity Market Figure III.2 Structure of Malaysian Electricity Supply Industry Figure III.3 Structure of the Electricity Market in Thailand Figure III.4 Policymaking Bodies in the Electricity Sector in Thailand Figure III.5 Structure of Electricity Industry in Singapore Figure VI.1 Histogram of Lifeline Discounts Figure VI.2 Maximum Average Price based on RAB valued at Historical Cost vii

11 List of Acronyms of Philippine Distribution Utilities ABRECO AEC AKELCO ALECO ANECO ANTECO ASELCO AURELCO BANELCO BASELCO BATANELCO BATELEC I BATELEC II BELS BENECO BILECO BISELCO BLCI BOHECO I BOHECO II BUSECO CAGELCO I CAGELCO II CAMELCO CANORECO CASURECO I CAPELCO CASELCO CASURECO II CASURECO III CASURECO IV CEBECO I CEBECO II CEBECO III CEDC CELCO CELCOR CENECO CENPELCO CEPALCO CLPC COTELCO DANECO DASURECO DECORP DIELCO DLPC DORECO DORELCO ESAMELCO FIBECO FICELCO Abra Electric Cooperative, Inc. Angeles Electric Corporation Aklan Electric Cooperative Albay Electric Cooperative Agusan del Norte Electric Cooperative Antique Electric Cooperative Agusan del Sur Electric Cooperative Aurora Electric Cooperative - Mainland Bantayan Island Electric Cooperative Basilan Electric Cooperative Batanes Electric Cooperative Batangas I Electric Cooperative Batangas II Electric Cooperative Bauan Electric Lights System Benguet Electric Cooperative Biliran Island Electric Cooperative Busuanga Island Electric Cooperative Bohol Light Company, Inc. Bohol I Electric Cooperative Bohol II Electric Cooperative Bukidnon II Electric Cooperative Cagayan I Electric Cooperative Cagayan II Electric Cooperative Camiguin Electric Cooperative Camarines Norte Electric Cooperative Camarines Sur I Electric Cooperative Capiz Electric Cooperative Cagayan de Sulu Electric Cooperative Camarines Sur II Electric Cooperative Camarines Sur III Electric Cooperative Camarines Sur IV Electric Cooperative Cebu I Electric Cooperative Cebu II Electric Cooperative Cebu III Electric Cooperative Clark Electric Distribution Corp. Camotes Island Electric Cooperative Cabanatuan Electric Corporation Central Negros Electric Cooperative Central Pangasinan Electric Cooperative Cagayan Electric Power & Light Power Inc. Cotabato Light & Power, Inc. Cotabato Electric Cooperative Davao del Norte Electric Cooperative Davao del Sur Electric Cooperative Dagupan Electric Corporation Dinagat Island Electric Cooperative Davao Light and Power Company Davao Oriental Electric Cooperative Don Orestes Romualdez Electric Cooperative Eastern Samar Electric Cooperative First Bukidnon Electric Cooperative First Catanduanes Electric Cooperative viii

12 FLECO GUIMELCO IEEC IFELCO ILECO I ILECO II ILECO III ILPI ISECO ISELCO I ISELCO II KAELCO LANECO LASURECO LEYECO I LEYECO II LEYECO II LEYECO III LEYECO IV LEYECO V LUBELCO LUECO LUELCO MAGELCO MARELCO MASELCO MECO MERALCO MOELCI I MOELCI II MOPRECO MORESCO I MORESCO II NEECO I NEECO II Area I NEECO II Area II NOCECO NOLCO NORECO I NORECO II NORSAMELCO NUVELCO OMECO ORMECO PALECO PANELCO I PANELCO III PECO PELCO I PELCO II PELCO III PENELCO PRESCO PROSIELCO QUEZELCO I First Laguna Electric Cooperative Guimaras Electric Cooperative Ibaan Electric Corporation Ifugao Electric Cooperative Iloilo I Electric Cooperative Iloilo II Electric Cooperative Iloilo III Electric Cooperative Iligan Light & Power, Inc. Ilocos Sur Electric Cooperative Isabela I Electric Cooperative Isabela II Electric Cooperative Kalinga-Apayao Electric Cooperative Lanao Del Norte Electric Cooperative Lanao del Sur Electric Cooperative Leyte I Electric Cooperative Leyte II Electric Cooperative Leyte II Electric Cooperative Leyte III Electric Cooperative Leyte IV Electric Cooperative Leyte V Electric Cooperative Lubang Electric Cooperative La Union Electric Company, Inc. La Union Electric Cooperative Maguindanao Electric Cooperative Marinduque Electric Cooperative Masbate Electric Cooperative Mactan Electric Company Manila Electric Company Misamis Occidental I Electric Cooperative Misamis Occidental II Electric Cooperative Mountain Province Electric Cooperative Misamis Oriental I Electric Cooperative Misamis Oriental II Electric Cooperative Nueva Ecija I Electric Cooperative Nueva Ecija II Area I Electric Cooperative Nueva Ecija II Area II Electric Cooperative Negros Occidental Electric Cooperative Net operating loss carry-over Negros Oriental I Electric Cooperative Negros Oriental II Electric Cooperative Northern Samar Electric Cooperative Nueva Vizcaya Electric Cooperative Occidental Mindoro Electric Cooperative Oriental Mindoro Electric Cooperative Palawan Electric Cooperative Pangasinan I Electric Coopertive Pangasinan III Electric Cooperative Panay Electric Company, Inc. Pampanga I Electric Cooperative Pampanga II Electric Cooperative Pampanga III Electric Cooperative Peninsula Electric Cooperative Pampanga Rural Electric Cooperative Province of Siquijor Electric Cooperative Quezon I Electric Cooperative ix

13 QUEZELCO II QUIRELCO ROMELCO SAJELCO SAMELCO I SAMELCO II SEZC SFELAPCO SIARELCO SIASELCO SOCOTECO I SOCOTECO II SOLECO SORECO I SORECO II SUKELCO SULECO SURNECO SURSECO I SURSECO II TARELCO I TARELCO II TARELCO II TAWELCO TEI TIELCO TISELCO ZAMCELCO ZAMECO I ZAMECO II ZAMSURECO I ZAMSURECO II ZANECO Quezon II Electric Cooperative Quirino Electric Cooperative Romblon Electric Cooperative San Jose City Electric Cooperative Samar I Electric Cooperative Samar II Electric Cooperative Subic Enerzone Corporation San Fernando Electric Light & Power Company Siargao Island Electric Cooperative Siasi Electric Cooperative South Cotabato I Electric Cooperative South Cotabato II Electric Cooperative Southern Leyte Electric Cooperative Sorsogon I Electric Cooperative Sorsogon II Electric Cooperative Sultan Kudarat Electric Cooperative Sulu Electric Cooperative Surigao Del Norte Electric Cooperative Surigao del Sur I Electric Cooperative Surigao del Sur II Electric Cooperative Tarlar I Electric Cooperative Tarlac II Electric Cooperative Tarlar II Electric Cooperative Tawi-Tawi Electric Cooperative Tarlac Electric, Inc. Tablas Island Electric Cooperative Ticao Electric Cooperative Zamboanga City Electric Cooperative Zambales I Electric Cooperative Zambales II Electric Cooperative Zamboanga Del Sur I Electric Cooperative Zamboanga Del Sur II Electric Cooperative Zamboanga Del Norte Electric Cooperative x

14 List of Other Acronyms APRI AR ARP BCQ BPP BST CCGT CEPA CERA COC CP CPI CRB CWIP DOE DSM DUs ECs EGAT EGCO EHT EIA EMA EMC ENCON Fund EPIRA EPPA EPPO ERB ERC ESC ESP ETAM EXSUP FAC FCPT FIT GCGI GPRICE GST HEUC HTH HTL HTS ICERA IEA IEC IED IMO IPPA IPPs IRR AP Renewables, Inc. Annual Report Allocated Regulated Price Bilateral Contracts Quantity Biaya Pokok Penyediaan Bulk Supply Tariff Combined Cycle Gas Turbine Committee on Energy Policy Administration Currency Exchange Rate Adjustment Coal Operating Contract Composite Price Consumer Price Index Central Registry Body Construction-work-in-progress Department of Energy Distribution, Supply and Metering Distribution Utilities Electric Cooperatives Electricity Generating Authority of Thailand Electricity Generating Company Extra High Tension Energy Industry Act Energy Market Authority Energy Market Company Energy Conservation Promotion Fund Committee Electricity Power Industry Restructuring Act Electric Power Purchase Agreement Energy Policy and Planning Office Energy Regulatory Board Energy Regulatory Commission Energy Supply Contract Effective Settlement Price Electricity Tariff Adjustment Mechanism Excess Supply Fuel Adjustment Cost Fuel Cost Pass-Through Feed-in-Tariff Green Core Geothermal Inc. Generation Price Goods and Services Tax Hourly Electricity Uplift Charge High Tension High High Tension Large High Tension Small Incremental Currency Exchange Rate Adjustment International Energy Agency International Energy Consultants Investigation and Enforcement Division Independent Market Operator Independent Power Producer Administrator Independent Power Producers Implementing Rules and Regulations xi

15 ITH JCPC JETRO LGUOU LMP LRMC MAP MC MCC MCE MCP MDOM MEA MEUC MO MOEN MOPS MSSL MSW NEA NEMS NEPC NGCP NPC NRES ODRC OECD PEA PEAKDEM PEMC PFC PIOUs PIS PLN PPA PSA PSALM PSC PSO RAB RATCH RCOA RDWR RE RFSC RORB RSEC-WR RTWR SEP SESB SESCO SMEC SMP SO SP Income Tax Holiday Joint Congressional Power Commission Japan External Trade Organization Local Government Unit-Owned Utility Locational Marginal Price Long Run Marginal Cost Maximum Average Price Monitoring and Compliance Members Contribution for Capital expenditure Market Clearing Engine Market Clearing Price Market Dispatch Optimization Model Metropolitan Electricity Authority Monthly Electricity Uplift Charge Market Operator Ministry of Energy Mean of Platts Singapore Market Support Services Licensee Municipal Solid Waste National Electrification Administration National Electricity Market of Singapore National Energy Policy Council National Grid Corporation of the Philippines National Power Corporation New and Renewable Energy Sources Optimized Depreciated Replacement Cost Organization for Economic Cooperation and Development Provincial Electricity Authority Peak Demand Philippine Electricity Market Corporation Power Factor Charge Private Investor-Owned Utilities Performance Incentive Scheme Perusahaan Listrik Negara Purchase Power Agreement Power Supply Agreement Power Sector Assets and Liabilities Management Corporation Power Supply Contract Power System Operator Regulatory Asset Base Ratchaburi Electricity Generating Holding Public Company Ltd Retail Competition and Open Access Rules for Setting Distribution Wheeling Rates Renewable Energy Reinvestment Fund for Sustainable Capital expenditures Rate of Return Base Rules for Setting Electric Cooperatives Wheeling Rate Rules for Setting the Transmission Wheeling Rates Singapore Electricity Pool Sabah Electricity SDN Berhad Syarikat Sesco Berhad San Miguel Energy Corporation System Marginal Price System Operator Singapore Power xii

16 SPPs SPUG SREP T & D TMI TNB TOU TRANSCO TSC UC USEP VAT VQ VSPPs WACC WCF WEP WESM Small Power Producers Strategic Power Utility Group Small Renewable Energy Producers Transmission and Distribution Therma Marine Incorporated Tenaga Nasional Berhad Time-of-Use National Transmission Company Transition Supply Contract Universal Charge Uniform Singapore Energy Price Value Added Tax Vesting Quantity Very Small Power Producers Weighted Average Cost of Capital Working Capital Factor Wholesale Electricity Price Wholesale Electricity Spot Market xiii

17 Executive Summary Surveys after surveys on electricity prices invariably show the Philippines to have one of the highest in the region. And yet in 2001, the Philippines introduced competition and regulatory reforms in its electricity market to address uncompetitive prices. In the decade that followed, however, electricity prices increased faster than inflation, which kept Philippine rates above other developing countries. This study analyzed the structure and individual components of Philippine electricity prices, and compared them with rates in selected countries in Southeast Asia, namely Singapore, Indonesia, Malaysia and Thailand. The tariffs in these selected economies were adjusted to approximate cost of supply and ensure comparability. Changes in regulations and policies were also simulated to identify impact on end user prices. The prices were constructed based on four model cases: (i) a residential customer with monthly consumption of 200 kwh; (ii) a commercial customer connected to low voltage wire with 3 MWh monthly consumption and 16 kw peak demand; (iii) an industrial customer connected to low voltage wire with 50 MWh monthly consumption and 195 kw peak demand; and (iv) an industrial customer connected to high voltage wire with 200 MWh monthly consumption and 520 kw peak demand. Philippine Electricity Prices Between 2004 and 2011, MERALCO prices increased by an average annual rate of 6.9 to 8.7 percent, depending on customer class, whereas average inflation during the period was 4.8 percent. As a result, real electricity prices increased, which can be traced to removal of subsidies, introduction of new taxes (particularly VAT in 2006) and adjustment in distribution charges. Table 1. MERALCO Electricity Tariffs by Customers Class, Low Voltage Residential Commercial Low Voltage Industrial High Voltage Industrial Price per kwh (nominal): Average annual change (%) Price per kwh (in 2000 prices): Average annual change (%) Although MERALCO s customers account for about three-fifths of total electricity consumption, the prices of this largest distribution utility (DU) do not represent the Philippines. Each of the 140 DUs in the country follows a regulated price schedule that reflects supply conditions in their respective franchise area. The upshot is a wide variation of prices across localities. A residential customer, for example, may be charged from Php5.50 to Php per kwh depending on location. To represent these different prices, a base composite price (i.e., an average price, weighted by actual consumption and after removing transitory elements) was constructed for each model case. In 2011, the base composite prices by customer class and major island group were as follow. xiv

18 Table 2. Base Composite Prices by Customer Class and Region (per kwh in Philippine peso) Region Residential Low Voltage Commercial Low Voltage Industrial High Voltage Industrial NCR Luzon Visayas Mindanao All regions With rate rebalancing due to industry reforms, prices have been aligned with costs. As a result, residential customers pay 19% more per kwh than industrial customers, while a residential customer in Luzon pays 44% more than one in Mindanao. Locational pricing distinguishes the Philippines from its neighbors where a uniform price schedule is adopted in all parts of Thailand and Singapore, and most parts of Indonesia and Malaysia. Prices are also more volatile in the Philippines since the schedules change monthly, as opposed to quarterly in Thailand and Singapore (for noncontestable customers) and irregularly in Indonesia and Malaysia. In addition, residential customers are still heavily subsidized in Indonesia, Malaysia and Thailand, whereas inter- and intra-class subsidies have been eliminated in the Philippines due to reforms. Benchmarking Philippine Prices That pricing structure and regulation are different across countries underscores the pitfall of drawing conclusions from a mere comparison of retail tariffs. In 2011, the retail tariffs in the five countries are as follow: Table 3. Comparative Electricity Retail Prices, 2011 (in Philippine peso per kwh) Low Voltage Low Voltage High Voltage Residential Commercial Industrial Industrial Philippines Singapore Indonesia Malaysia Thailand Clearly, while Philippine prices are close to Singapore s, they are a multiple of those prevailing in Indonesia, Malaysia and Thailand. Residential customers in the Philippines pay nearly four times the price levied on their counterpart in Indonesia, while industrial customers are charged at least 60 percent more than their equivalent in Thailand. Several factors may explain these wide differences. One is tax: effectively 9% in the Philippines, as opposed to 6% in Malaysia and 7% in Singapore and Thailand, albeit 10% in Indonesia. But the bigger contributor to the price differences is the implicit subsidies to state-owned utilities. The International Energy Agency (IEA) estimated that the electricity subsidies in 2011 in Indonesia, Malaysia and Thailand were at least 5.56, 0.94 and 5.67 billion US dollars, respectively. These estimates are conservative when compared to actual government transfers to the Indonesian utility (Perusahaan Listrik Negara) of US$10.24 billion just in The Malaysian utility (Tenaga Nasional Berhad) received a much smaller direct transfers (about US$153 million in 2010; undisclosed in 2011), but hefty fuel discount of at least 26% on the market price of indigenous fuel. The actual subsidy on Malaysian electricity price is reckoned to be about six times the IEA s estimate. The subsidy in xv

19 Thailand, on the other hand, is least transparent since it is passed through domestic price of indigenous natural gas. When taxes and subsidies are removed, the cross-country tariffs are as shown below. Table 4. Comparative Electricity Tariffs after Adjusting for Taxes and Subsidies (per kwh, in Philippine peso) PHL SGP INA MAL THA Residential Low voltage commercial Low voltage industrial High voltage industrial *Based on IEA s subsidy estimate for Thailand; direct transfers to PLN for Indonesia; deduced from the 10 th Malaysian Plan for Malaysia. While Philippine prices are still higher despite adjustments in taxes and subsidies, the gaps are not as sizeable as were found in simple comparison of retail tariffs. Yet they exist nonetheless. A plausible explanation is market structure, which while ostensibly critical, is difficult to track in terms of its contribution to tariff. The industry structure in Indonesia, Malaysia and Thailand vertically integrated and managed by public utilities is bound to produce different prices compared to a market-, private sector-led, unbundled industry such as the one prevailing in the Philippines and Singapore. The Thai public utilities, for example, subsist on a return on capital of 7.5% for the Electricity Generation Authority of Thailand and 5.73% for its two distribution utilities, compared to about 15% for private DUs in the Philippines. Moreover, when the industry is disintegrated or unbundled, profit margins at each stage of production could pile up on prices, unless market competition and prudent regulation are able to keep a lid on margins. If regulation fails to facilitate effective competition, prices in an unbundled industry are inevitably higher than under vertical integration. Price differences can also reflect inherent differences in costs of supply due to network conditions, load demand profile and generation mix, among others. Singapore s network costs are marginal and unique because of its geographic size and dense customer base. Most of the differences in supply conditions are however less obvious and can only be properly diagnosed by a cost of service study, which is beyond the scope of this work. Simulations of Policy Changes Can Philippine electricity prices be reduced without misaligning them with costs or distorting market signals? The study examined the impact on prices of some of the proposed policy adjustments involving tax restructuring, elimination of subsidies, and redistribution of royalties from indigenous fuels. The use of historical instead of current asset values in calculating distribution tariffs, and the change in the basis of regulation of electric cooperatives from cash- to performance-based were also simulated. Possible changes in composite prices as a result of these policy adjustments are summarized below. Table 5. Simulated Reduction in Composite Prices As a Result of Policy Adjustments (per kwh in Philippine peso) Residential LV Commercial LV Industrial HV Industrial Zero VAT % VAT % VAT replacing all taxes xvi

20 Residential LV Commercial LV Industrial HV Industrial 3% franchise tax replacing all taxes Removal of lifeline discounts Elimination of all subsidies Proportionate rebate of geothermal royalties Additional rebates to DUs with geothermal BCs Rebate of natural gas royalties to MERALCO customers only Rebate of natural gas royalties to Luzon customers only Rebate of natural gas royalties to industrial customers only Uniform rebate of natural gas royalties Completion of EC transition to PBR No revaluation of MERALCO assets Adjustments in taxes, followed by rebates of natural gas royalties produce the largest potential reduction in prices. But none of the foregoing results should be viewed as endorsement of any policy change. The merit of rebating to electricity consumers the government share on the utilization of indigenous fuels is debatable since it tends to distort the relative prices of fuels. Similarly, the removal of VAT on electricity would mean less fiscal resources for other public services. Even as asset revaluation increases distribution charges, there are conceptual and practical arguments that justify the use of replacement, instead of historical, costs in asset pricing. Moreover valid objections can be raised in computing rebates on the basis of kwh consumption since it favors heavy users and can be seen as a disincentive for energy efficiency and conservation. The results of the counterfactual simulations in this study are therefore best seen as mere demonstration of the influence that policies and regulations still have on electricity tariffs despite the move towards a more market-based price determination. Considering that generation cost constitutes at least half of electricity prices, the study also analyzed the trend in wholesale electricity prices. It found the spot market prices are influenced by levels of offered supply and peak demand but more by the latter. A 10% increase in excess supply (i.e., offers less demand) is projected to reduce spot prices by 10%, while a 10% reduction in peak demand is expected to bring down spot prices by 20%. Over time, bilateral contract prices are observed to follow the trend in spot prices. This implies that the potential of bilateral contracts to cause a downward shift in prices can only hold in the short term. Conclusion All benchmarking exercises involving electricity prices suffer a major difficulty that even as electricity is considered a homogeneous commodity, it has no international reference price. The fact that a country s prices are higher than other countries of similar level of economic development is certainly a reasonable cause of concern because the economic impact is broad and profound. However, it should not form basis for market intervention without adequate understanding of the causes and nature of higher prices. xvii

21 A major motivation for this inquiry is to provide inputs to a brewing debate on whether the Philippines has taken a wrong policy turn when it restructured the electricity market. Critics of the restructuring have cited the still uncompetitive Philippine prices after more than a decade. Yet Indonesia and Malaysia are now coming into terms on the need to restructure their respective industries from the traditional vertically-integrated, state-managed structure to one that is market-based and private sector-led. They recognize that their current tariff structures and fuel subsidies are unsustainable; that their public utilities are underperforming because the market structure does not create enough incentives for efficiency; and that the inefficiencies in the electricity sector are affecting the rest of the economy as it attracts industries dependent on subsidized energy. But just like the Philippines more than a decade ago, these economies are constrained by political realities from pursuing market reforms. On this score, it would be odd to blame reforms that other countries are now seeking to emulate. xviii

22 I. Background 1. Motivation The passage of the Electric Power Industry Reform Act (EPIRA) of 2001 was occasioned by unabated increases in electricity prices, heavy indebtedness of public electric utilities, and perennial threat of supply problems which the government had difficulty addressing. It became clear that a centrally managed electricity system, mainly owned and run by the State, was no longer tenable. This prompted the restructuring and liberalization of the market. With the private sector stepping up on the roles previously belonging to the State, expectations were raised that the sector would become more efficient, and as a result, electricity prices would decline substantially. But in the past decade, prices have generally moved in opposite direction so that Philippine rates remain above those of other countries in the region. A survey conducted by the Japan External Trade Organization (JETRO) 1, for example, revealed that the Philippine capital had the highest electricity rate among 31 cities in Asia and Oceania in The average rate for general use in Manila was US$0.23/kwh, compared to US$0.20/kwh in Singapore, US$0.08/kwh in Bangkok, US$0.11/kwh in Kuala Lumpur, and US$0.09/kwh in Jakarta. Dhaka had the least, at US$0.06/kwh. Although the survey did not include Tokyo, which is reputed to have the highest rate in the region, the fact that the Philippine rates are above other countries with whom it competes for foreign investments and trade is by itself disturbing. Corroborating JETRO s survey is a recent study by the International Energy Consultants (IEC) showing Philippine electricity prices higher than other countries in Asia and Pacific. Although comparable to some developed economies, like Singapore and Australia, Philippine prices are significantly higher than prices prevailing in other developing economies in the region. The Philippines ranked 9 th among 44 economies and 2 nd in Asia behind Japan. 2 The World Bank-IFC s 2012 Doing Business also reported that securing electricity connection in the Philippines is several times costlier than in neighboring countries. The cost of getting connection in the Philippines is 762 percent of its income per capita, while only 78 percent in Thailand, 96 percent in Malaysia and 31 percent in Singapore. It also takes longer to secure connection in the Philippines, averaging 50 days, compared to 35 and 31 days in Thailand and Singapore, respectively. Since these findings relate to the expectations borne by the industry restructuring, they deserve attention. The key issue is whether the results of these different surveys suggest a failure in market reforms. And yet it is arguable if expectations of lower electricity prices are grounded. To be clear, the objective of market reform is to ensure transparent and reasonable prices of electricity in a regime of free and fair competition. It is conceivable that when prices are aligned with costs and subsidies are removed, they could actually rise. But it is also rational to expect the introduction of competition to eliminate the inefficiencies of past monopoly structure, hence reduce costs and consequently prices. The anticipation of lower prices following a decade of reforms is therefore not entirely unfounded. 1 JETRO (2011), The 21 st Comparative Survey of Investment-Related Costs in 31 Major Cities and Regions in Asia and Oceania, April. 2 International Energy Consultants (2012), Regional Comparison of Retail Electricity Tariffs: Executive Summary, June. The study used MERALCO prices to represent the Philippines. Final Report Page 1

23 Costs and prices in the electricity market are functions of a host of factors of which regulation is only one. High prices are not always signals of wrong policy turns in as much as low prices do not necessarily reflect efficiency. Prices that actually reflect costs are far more complex (and uncertain), as they are affected by gyration in fuel prices, generation mix, network conditions and weather, among others. The costs of generating and supplying electricity vary with time of delivery, location and usage of consumers. Therefore, even if market reforms deliver on expectations of fostering economic efficiency and aligning prices and costs there may be no palpable reduction in tariffs if the underlying costs are unaffected by industry restructuring or changes in regulation. Cognizant of these complex relationships, electricity tariffs should be analyzed in relation to the structures of production and market where they apply. Where market structures are not comparable, so are their respective tariffs. To describe one country s tariffs as high or excessive, much less judge the effectiveness of reforms based merely on cross-country comparison of end-user prices is misleading, if not unwarranted. Since there is no accepted international electricity price, the outcome of any tariff benchmarking is at best suggestive, and should not be taken as evidence or measure of excessiveness. 2. Objectives and Scope This study has three main tasks: (i) analyze the structure and individual components of Philippine electricity prices, and compare them with selected ASEAN countries; (ii) approximate supply costs from tariffs and benchmark Philippine costs against those of selected economies; and (iii) identify policy interventions that could lower prices of electricity in the Philippines. It aims to contribute to the discourse on whether Philippine prices are excessive, and if so, whether high prices are a fair indictment of the effectiveness of market reforms. If it can be shown that market structure and regulations do not account for the higher prices of electricity in the Philippines than elsewhere, it should shift the burden away from market restructuring and reforms in explaining the comparative levels in prices. Four other electricity markets are included in this study, namely Indonesia, Thailand, Malaysia and Singapore. These countries were selected mainly because the Philippines is always benchmarked against them. But in fact, only the markets of Singapore and the Philippines are comparable. The markets in Thailand, Indonesia and Malaysia are similar to the Philippines before EPIRA, i.e., centrally managed by a state utility. The similarity ceased after EPIRA. Nonetheless, the electricity prices in the Philippines are still being compared to prices in these countries, especially when assessing the Philippine competitiveness in the region. The study is limited to end-user tariffs in 2011 and regulations directly affecting them. There are other significant factors affecting costs and prices that are not covered in this inquiry, e.g., conditions of network infrastructure and characteristics of load demand. It does not purport to uncover all factors that may explain the level of Philippine tariffs. Nor is it able to present the true supply costs in the markets covered, although tariffs are adjusted by the best available information for comparability. This study proceeded in four phases. The first phase was a general assessment of the market structure and regulation of electricity markets in the five countries. Phase II examined the conditions affecting electricity prices in these economies, particularly price determination, regulations and subsidies. Phase III adjusted the tariffs to estimate and compare the underlying costs of supplying electricity in these markets. The final phase performed counterfactual simulations on Philippine prices to identify the impact of regulations and identify possible interventions to lower the tariffs faced by consumers. Final Report Page 2

24 Two sets of findings emerged from this exercise. The first is a comparison of electricity prices in the five countries for residential, commercial and industrial customers. It shows prices before and after adjustments for taxes and computable subsidies, and expresses them into common currency units. The second set of results pertains to the impact of regulations on Philippine electricity prices. These include lifeline discounts and other transfers, taxes, royalties on indigenous fuels, valuation of assets for rate determination, and regulatory reset in electric cooperatives. The results could point to potential areas of intervention that can reduce consumer burden without distorting prices. 3. Model Cases This study adopts the model case approach to analyze and compare tariffs. It involves constructing case scenarios and calculating tariffs that would apply using the price schedules of distribution utilities (DUs) or suppliers where retail competition exists. An alternative approach calculates an average or representative price, which may be an average of unit prices that apply to different customer categories, or an average revenue obtained by dividing total income from electricity sales by the units (or kwh) sold. Average unit price is less representative than average revenue if customer classes are of different sizes or there are wide variations in unit prices. On the other hand, since retail prices normally consist of fixed and variable components, average revenue tends to be lower, the higher the average load of the large segment of consumers, since the fixed component of the price is spread over a larger load. As a result, even if two economies have the same price schedules, the one with a larger average load would appear to have a lower rate. The chosen approach has the advantage that tariff comparison would not be distorted by differences in load. Moreover, since the base models control for differences in customer attributes and location, any remaining tariff variations may be attributed to differences in market structure, regulation or supply condition. However, this approach could be more complicated if the fee schedules followed by utility companies are not readily available, transparent or easy to implement. Four model cases were constructed for purposes of this study. Table I.1 Assumptions in Model Cases Residential Low voltage Commercial Low voltage Industrial High voltage Industrial Typical customer Household Business Small industrial Medium industrial Received voltage Less than 1 kv Less than 1 kv 13.2 kv Peak demand (kw) Monthly consumption (kwh) 200 3,000 50, ,000 Power factor 60% 60% 60% 60% The objective is to estimate the tariff that would apply to a particular customer in a given country based on an assumed monthly consumption during the year This exercise is however fraught with several challenges. First, different tariffs may apply to customers of the same type and consumption depending on their location, e.g., urban versus rural. But in Malaysia, Indonesia and Thailand, a single tariff schedule is applied nationwide. In Singapore, regulated prices apply to non-contestable consumers (those with less than 10 MWh monthly consumption), but contestable consumers can negotiate with competitive suppliers bilaterally. Thus, the actual rates paid by contestable consumers are not publicly known. In the Philippines, each of the 140 DUs has its own price schedule. This necessitates the computation of a weighted average price which is discussed in the next section. Final Report Page 3

25 Prices can vary seasonally with fuel cost; therefore the choice of period when tariffs are calculated can influence the results. Since the generation mix is different in each country, picking a benchmark month can distort the comparison as it may happen that the price of the fuel predominantly used in one country is artificially high during the chosen month. This is less of a concern, however, in heavily regulated markets of Indonesia and Malaysia where price schedules are changed infrequently and often influenced by political mood. The last revision in price regulation in Indonesia was in 2009, hence electricity prices remained constant throughout In Malaysia, prices were last adjusted in June 2011; a 1% feedin-tariff was imposed beginning September In Thailand and Singapore, price adjustments are made quarterly to reflect changes in fuel costs; in addition, base tariffs in Thailand are adjusted annually. Philippine prices, on the other hand, are adjusted every month to reflect changes in generation costs. Given the different periods of price adjustments, it is necessary to take a time frame longer than one month. In this study, the average tariffs for 2011 were estimated. Another difficulty in applying case scenarios is the absence of common customer categories among the five selected countries, and even among DUs in the Philippines. Tariffs are usually differentiated by customer class and voltage levels. A low voltage commercial customer class in one country may not have an exact match with a customer class in another country. The only customer category that is common in all five countries is residential or household. Even this category has subclasses in some countries like Indonesia, but none in others. Thus, it is only possible to compare tariffs for the closest equivalent categories, as is done in this report. Table I.2 Customer Classes used in Comparing Prices Residential Commercial Philippines* RGSA General Service B NIS Small Indonesia Malaysia Thailand Singapore R-1/TR (category 1, power limit 450 VA) Tariff A (Domestic) Residential service Low tension supplies, domestic B-2/TR (power limit 6.6 to 200 kva) Tariff B (Low voltage commercial) Small general service (less than 22 kv) Low tension supplies, nondomestic Low voltage Industrial General Power Industrial Medium Secondary I-2/TR (power limit 14 to 200 kva) Tariff D (Low voltage industrial) Medium general service (less than 12 kv) High tension small (HTS) supplies High voltage Industrial General Power 13.8/13.2 kv Industrial Large I-3/TR (power limit greater than 200 kva) *MERALCO s customer classes. See Annex I for customer classes in other Philippine DUs. Tariff E1 (Medium voltage industrial) Medium general service (12 24 kv) High tension large (HTL) supplies Final Report Page 4

26 In the Philippines, DUs follow different customer segmentation. The Energy Regulatory Commission (ERC) has ordered a regulatory reset for electric cooperatives (ECs) to harmonize customer categories. Most of the ECs are still transitioning to this new regime during Private investor-owned utilities (PIOUs) are, however, allowed to maintain their own categories. Finally, another challenge in benchmarking tariffs is the different structures of tariffs across countries, which requires imposing several assumptions on customers and their usage to ensure comparability. Some countries have flat rates; others charge by time and day of use or by contracted capacity. In some countries, the demand charge is based on peak demand, while it is based on reactive power in others. For comparability, where either flat or time-of-use (TOU) rates are applied, the former is used since few avail of TOU rates in the Philippines. If all are assessed by TOU, it is assumed that 60% of consumption occurs during peak hours. Contracted capacity is pegged at the level of average load, and a power factor of 60% is assumed for all customer classes Structure of the Report The next section focuses on the Philippine electricity market its new structure since the reform, price components, trends and pertinent regulations. Given the unique structure of the Philippine market, where there are some 140 submarkets with individual price schedules, a composite price is constructed in each model case to represent the Philippine market. Section III briefly describes the market structure and regulatory regimes in Indonesia, Malaysia, Thailand and Singapore. This section underscores the monopoly structure and heavy regulation in these markets except Singapore, which has many similar structural and regulatory features as the Philippine market. A more detailed discussion of these markets is presented in a separate volume to this report. Section IV elaborates on the price regulation in other selected ASEAN economies and derives the tariffs in these markets based on the four model cases. The Philippine composite prices are then compared with these derived tariffs in Section V. It is found that even after accounting for taxes, subsidies and differences in purchasing power, Philippine prices are significantly above those prevailing in other ASEAN economies. Section VI examines possible changes in regulation that may affect Philippine prices. These counterfactual simulations reveal the extent regulations are affecting current tariff levels. The pertinent regulations refer to taxes, lifeline rates and other transfers to specific customer classes, pricing of indigenous fuels, valuation of regulatory asset base and incentive-based price regulation applied to ECs. The final section summarizes the key findings and conclusions derived from cross-country comparison of electricity tariffs. In the face of clamor to provide relief to Philippine electricity consumers, this study cautions against quick-fix solutions that can undermine the gains that have been achieved by market reforms. 3 This is admittedly a conservative but nonetheless commonly used assumption on power factor rating. Final Report Page 5

27 II. The Philippine Electricity Market 1. Market Structure From 1972 to 1986 the National Power Corporation (NPC), a government corporation, owned and operated the generation and transmission facilities in the Philippines. But the power shortages in the late 1980s forced the government to end its monopoly in generation of electricity by allowing private companies to build and operate generating facilities. 4 In 1993, the Electric Power Crisis Act was passed and NPC entered into contracts with independent power producers (IPPs), with the government undertaking to guarantee NPC s obligations. Thus before EPIRA was passed in 2001, electricity was already being generated by IPPs and NPC, but NPC maintained control of generation. The IPPs operated under a purchase power agreement (PPA) whereby NPC agreed to purchase the energy output of the IPPs (mostly on a take-or-pay basis) and the government guaranteed NPC s obligations. The transmission lines were owned and operated by NPC. Distribution of electricity to endusers was largely the responsibility of the private sector. The distribution companies consisted of private investor-owned utilities with franchises from the government, a few local government unit-owned utilities, and numerous electric cooperatives. The Energy Regulatory Board (ERB) regulated the rates of NPC and of DUs. This structure changed with the enactment of EPIRA and has been evolving with the implementation of the reform program. 1.1 Generation Installed Capacity One of EPIRA s main objectives is to make generation of electric power competitive and open (EPIRA, Sec. 6). Consistent with this objective, EPIRA mandated the privatization of NPC generating units 5 and IPP contracts. The Power Sector Assets and Liabilities Management Corporation (PSALM) was created to assume ownership of NPC generation assets and IPP contracts, among others. The principal function of PSALM is to manage the orderly sale, disposition, and privatization of, among others, NPC generation assets and IPP contracts (EPIRA, Sec. 50). The privatization of the generation assets and IPP contracts proceeded slowly initially but accelerated in recent years. As of March 2012, only 7.9% of installed generation capacity is still owned and operated by NPC and PSALM; the rest is either owned or operated by private utilities. 6 Table II.1 Installed Generation Capacity in the Philippines by Ownership, 2012 (in MW) Luzon Visayas Mindanao Philippines Share(%) NPC/PSALM owned and , operated NPC/PSALM IPPs 1, , IPPs and DUs owned 6,185 1, , NPC/IPP contracted capacities 3,315 3, with IPPAs Total 11,388 2,063 1,769 15,220 Source: Energy Regulatory Commission (ERC). 4 This was provided for by Executive Order The assets of the Strategic Power Utility Group (SPUG) were exempted. The Agus and Pulangi Hydro complexes in Mindanao were excluded from privatization during the first 10 years of EPIRA s effectivity. Since hydroelectric plants account for about half of installed capacity in Mindanao, the government-owned and operated plants still make up about half of the installed capacity in the island. 6 ERC, Resolution No. 04, Series of Final Report Page 6

28 In the last five years, less than 1 GW was added to the Luzon and Visayas grids, and none to the Mindanao grid. This did not help avert the power shortages in Visayas and Mindanao that were anticipated since early The current installed capacity stands at 15,220 MW with three quarters (75%) located in Luzon (Table II.2). The dependable capacity is about 90% of total installed capacity. 7 Table II.2 Installed Generation Capacity in the Philippines by Grid (in MW) 2007* 2012** Average annual growth (%) Share (%) in 2012 Luzon 10,867 11, Visayas 1,507 2, Mindanao 1,867 1,769 (1.07) Total 14,241 15, *As of July. **As of March Source: Energy Regulatory Commission (ERC). Generation Mix The industry has been more successful in diversifying its generation mix than expanding its capacity. Until the late 1990s, oil and gas plants dominated generation. The current capacity is now balanced, with coal having the largest share of 30%, followed by hydro and natural gas, 24% and 19%, respectively. Geothermal plants account for less than 11%, while the combined capacity of renewable plants (biomass, wind and solar) is still insignificant at less than 1%. Table II.3 Installed Generation Capacity in the Philippines by Fuel Type, 2012 (in MW) Luzon Visayas Mindanao Philippines MW %Share MW %Share MW %Share MW %Share Coal 3, , Hydro 2, , Natgas 2, , Oil 1, , Geothermal , Wind Biomass Solar a Total 11, , , , a = less than 0.1 percent Source: Authors calculation based on ERC s data. 7 This is based on the DOE 2011 Power Statistics, which shows a dependable capacity of 14,477 MW out of installed capacity of 16,162 MW in Final Report Page 7

29 Some fuels however are more dominantly used than others at the grid level. As can be seen from Table II.3, coal is more dominantly used in Luzon, accounting for 32% of installed capacity, geothermal (41%) in Visayas, and hydro (54%) in Mindanao. Natural gas generation plants are concentrated in Luzon. Although hydroelectric plants have respectable shares in Luzon and Mindanao, they are a minor producer in Visayas. There is only one wind generation plant located in Luzon and only one solar plant located in Mindanao. The contribution of renewable energy is boosted by methane plants (12 MW) in Luzon and bagasse plants in Visayas (29 MW) and Mindanao (21 MW). Energy Output In 2011, the total generated power was 69,050 GWh, of which about two-thirds were supplied by coal and natural gas plants. Oil-based plants, while accounting for 16% of installed capacity, contributed less than 5% of total generation. Renewables provided a minuscule 0.3%. Table II.4 Energy Generation: Philippines, 2011 Plant Type Energy Output GWh % Share Coal 25, Natural Gas 20, Geothermal 9, Hydro 9, Oil 3, Wind Biomass Solar 1 a Total 69, a = less than 0.1 percent Source: 2011 Power Statistics, Department of Energy The breakdown of the energy output by grid is shown below. Table II.5 Energy Generation by Plant Type and Grid, 2011 Luzon Visayas Mindanao Plant Type GWh % Share GWh % Share GWh % Share Coal 19, , , Oil 1, , Natural Gas 20, Geothermal 3, , Hydro 4, , Wind Biomass Solar a Total 49, , , a = less than 0.1 percent Source: 2011 Power Statistics, Department of Energy 1.2 Transmission The transmission of electric power is a regulated common electricity carrier business, subject to the rate-making powers of the ERC. The privatization of the maintenance and operation of the transmission lines involved a two-step process. The first step was the creation of a government company called the National Transmission Company (TRANSCO), wholly owned by PSALM, to assume the electrical transmission function of NPC. Among its Final Report Page 8

30 functions, TRANSCO was mandated to provide open and nondiscriminatory access to its transmission system to all electricity users (EPIRA, Sec.9b). The second step was the privatization of the transmission system of TRANSCO. The approved privatization scheme is a 25-year concession contract to operate and maintain the transmission system, with the government retaining legal ownership of the transmission assets through TRANSCO. In December 2007 the concession was awarded to the National Grid Corporation of the Philippines (NGCP). NGCP formally took over the operation of the transmission system on 15 January NGCP acts as the System Operator and is regulated by ERC. 1.3 Distribution The distribution sector remains a regulated common carrier business requiring a national franchise. A DU has the obligation to provide services and connections to its system for any end-user within its franchise area and to provide open and nondiscriminatory access to its distribution system to all users (EPIRA, Sec. 22, 23). There are three types of DUs: private investor-owned utility (PIOU), local government unitowned utility (LGUOU), and electric cooperative (EC). In 2011 there were 20 PIOUs and LGUOUs and 120 ECs operating in the three grids (Table II.6) Table II.6 Number of Distribution Utilities in the Philippines, by Grid, 2011 Grid PIOUs and LGUOUs ECs Luzon Visayas 4 31 Mindanao 4 33 Total Source: ERC. These DUs allocate the generated electricity to end-users (residential, commercial, industrial, and others 8 ). About 8% of generated electricity is used by DUs and power plants (own-use), while 11% is lost during transmission and distribution (systems loss). Table II.7 Electricity Sales and Consumption: Philippines, 2011 Sector GWh % Share Residential 18, Commercial 16, Industrial 19, Others 1, Total Sales 56, Own-Use 5, System Loss 7, Total 69, Source: 2011 Power Statistics, Department of Energy 8 Others refer to public buildings, street lights, irrigation and others not elsewhere classified. Final Report Page 9

31 1.4 Supply Once retail competition is introduced, a new sector will be added to the electricity industry, namely, the supply sector. The supply of electricity refers to the sale of electricity by a party (called a supplier) other than the generator or distributor in the franchise area of a distribution utility using the wires of the distribution utility concerned. Retail competition allows suppliers to sell, broker, market or aggregate electricity to the end-users. In retail competition, customers can choose to buy from different retail suppliers. EPIRA stipulated five conditions before introducing retail competition and open access (RCOA), namely: (i) the establishment of the Wholesale Electricity Spot Market (WESM); (ii) unbundling of transmission and distribution charges; (iii) initial implementation of the crosssubsidy removal scheme; (iv) privatization of at least 70% of the total capacity of NPC s generating assets in Luzon and Visayas; and (v) transfer of NPC-IPP contracts to IPP administrators (IPPA). These conditions are deemed to have been complied with, although there are some NPC-IPP contracts that have yet to be transferred to IPPAs. The implementation of RCOA was initially stalled by the absence of a body to monitor the transactions between suppliers and contestable consumers. In November 2011, the Philippine Electricity Market Corporation (PEMC) was appointed by ERC to perform this function as the Central Registry Body (CRB). RCOA was slated to commence in the last quarter of Regulatory Regime 2.1 The Electric Power Industry Reform Act EPIRA was passed into law on 8 June It established the framework for reforming the electricity industry in the Philippines. Its primary objective is to restructure the industry in order to introduce competition and achieve gains in economic efficiency. Consistent with this objective, EPIRA divided the industry into four sectors, namely, generation, transmission, distribution and supply and declared that: (i) generation of electric power, a business affected with public interest, shall be competitive and open (EPIRA, Sec. 6); (ii) transmission of electric power shall be a regulated common electricity carrier business (EPIRA, Sec. 7); (iii) distribution of electricity shall be a regulated common carrier business (EPIRA, Sec. 22); and (iv) the supply of electricity is a business affected with public interest (EPIRA, Sec. 29). 2.2 Generation To introduce competition in the generation sector, it was necessary for EPIRA to mandate the privatization of NPC s generation assets and its IPP contracts and the creation of the WESM. Final Report Page 10

32 Privatization of NPC Generation Assets and IPP Contracts The privatization of NPC s generation assets and IPP contracts 9 is the responsibility of PSALM, a government corporation established by EPIRA to assume ownership of NPC s assets and contracts and eventually to sell them. Based on recent ERC s monitoring, the remaining plants owned and operated by NPC/PSALM as of March 2012 are Angat, Agus and Polangui hydroelectric power plants and several power barges in Visayas and Mindanao. Some 13 plants are still under IPP contracts, while 5 have been transferred to IPPAs. Eleven more IPP contracts are due for transfer to IPPAs between 2013 and To promote competition and prevent market power abuse, EPIRA stipulates a limit on concentration of ownership of generation companies. Sec. 45(a) states that no company or related group can own, operate or control more than 30 percent of the installed generating capacity of a grid or 25 percent of the national installed generating capacity. There have been expressed concerns that the sale of government generating assets will merely transfer market power from government to private sector. Other provisions related to generation are the following: (i) Since EPIRA provides that power generation is not a public utility operation, those engaged in power generation are not required to secure a national franchise; (ii) Sales of electricity by generation companies using renewable energy are zero-rated for VAT purposes; and (iii) Upon implementation of RCOA, generation prices will no longer be subject to regulation by the ERC (EPIRA, Sec. 6). Wholesale Electricity Spot Market Competition in the generation sector was introduced with the creation of WESM, an auction market for bulk trading of electricity where generators compete to sell electricity in a centralized pool, and distributors and bulk consumers buy from the pool. WESM is organized as a gross pool such that all generators physical sales of electricity are offered in the pool, and all purchases of electricity are drawn from the pool. The gross pool thus includes electricity sold through bilateral contracts between generators and DUs. The market participants include the Market Operator (MO), System Operator (SO) and trading participants, which consist of sellers (generating companies) and buyers or customers (DUs and bulk consumers). All generating companies with facilities connected to the transmission or distribution systems and all customers purchasing electricity supplied through the transmission system have to register as pool members. Trading is done every hour resulting in 24 hourly prices every day. Generators electronically submit offers in a day-ahead auction which specify the prices at which they are willing to supply quantities of electricity. A supply offer is in the form of a series of price-quantity blocks, each block (at least 5 MW) indicating how much electricity the generator is willing to sell at the indicated price. On the basis of the submitted offers, the Market Operator draws up a minimum-cost schedule of generators for dispatch. The minimum-cost schedule is obtained by ordering the price offers (called the merit order) from the lowest to the highest. Blocks of electricity in increasing order of cost are dispatched until the forecasted demand is covered. The highest price in the merit order (i.e., the price of the last block to be dispatched 9 Privatization of an IPP contract means the transfer to an entity, appointed by PSALM, to administer and manage the contracted energy of the IPP th Status Report on EPIRA Implementation, pp Final Report Page 11

33 that meets the demand) sets the market price, called the system marginal price (SMP), also called the market clearing price (MCP). Most generators supplying power to the grid are located far from the demand areas. This means that the costs of providing electricity to different locations (nodes 11 ) vary with transmission capacity constraint conditions and transmission losses. Therefore, SMP is adjusted to reflect transmission congestion and transmission losses, resulting in nodal prices. Cash settlement of all transactions in the wholesale market and other payments and charges (e.g., market fees) is the responsibility of the MO. However, market participants with bilateral contracts have the option to settle in the market or outside the market. WESM started market operations in the Luzon Grid in June 2006, and expanded to include the Visayas in December Although all generated electricity supplied to the national grid must be traded in WESM, generators and distributors are not prevented from entering into bilateral contracts to hedge against price gyrations in the spot market. However, Section 45(b) of EPIRA imposes the following limitations: For the purpose of preventing market power abuse between associated firms engaged in generation and distribution, no distribution utility shall be allowed to source from bilateral power supply contracts more than fifty percent (50%) of its total demand from an associated firm engaged in generation but such limitation, however, shall not prejudice contracts entered into prior to the effectivity of this ACT. 2.3 Transmission The transmission of electric power is a regulated common electricity carrier business. Before privatization the transmission system was separated from generation and a transmission company, the National Transmission Corporation (TRANSCO), was created and required to be privatized. The approved privatization scheme is a 25-year concession contract to operate and maintain the transmission system of TRANSCO with the government retaining legal ownership of the transmission assets. In December 2007, the concession was awarded to the National Grid Corporation of the Philippines (NGCP), a consortium of Monte Oro Grid Resources Corporation, Calaca High Power Corporation, and State Grid Corporation of China. Because transmission is a public utility operation, NGCP had to obtain a congressional franchise. NGCP formally took over the operation of the transmission system on 15 January NGCP acts as the System Operator and is regulated by ERC. EPIRA requires that NGCP provide all electricity users open and nondiscriminatory access to the transmission system. Moreover, Section 45 of EPIRA ring fences the transmission subsector through the following cross-ownership rules: No generation company, distribution utility, or its respective subsidiary or affiliate or stockholder or official of a generation company or distribution utility, or other entity engaged in generating and supplying electricity specified by ERC within the fourth civil degree of consanguinity or affinity, shall be allowed to hold any interest, directly or indirectly, in TRANSCO or its concessionaire. Likewise, TRANSCO or its concessionaire or any of its stockholders or 11 A node is a point on the electrical network system where electricity is either supplied to the network or withdrawn from the network. Final Report Page 12

34 officials or any of their relatives within the fourth civil degree of consanguinity or affinity, shall not hold any interest, whether directly or indirectly, in any generation company or distribution utility. Except for ex officio governmentappointed representatives, no person who is an officer or director of TRANSCO or its concessionaire shall be an officer or director of any generation company, distribution utility or supplier. However, Republic Act 9511, the law awarding franchise to NGCP, relaxed this absolute cross-ownership prohibition by allowing the franchisee, its stockholders, directors and officers to own shares of stocks in a generation or distribution utility listed in the stock exchange, so long as the ownership does not exceed 1 percent of outstanding shares of the listed utility (Section 7, RA 9511). 2.4 Distribution Distribution of electricity remains a common carrier business requiring congressional franchise and may be undertaken by private DUs, cooperatives, local government units, and other entities authorized by the Energy Regulatory Commission. Any distributor is required by law to provide open and nondiscriminatory access to its system to all users and can impose and collect distribution wheeling charges and connection fees from such users as approved by the ERC. 2.5 Supply The supply of electricity refers to the sale of electricity by a party, called supplier, other than the generator or distributor in the franchise area using the wires of the DU. In retail competition, customers can choose to be serviced by the DU in the franchise area or by retail suppliers. Most restructured electricity markets including the Philippines follow a progressive implementation of retail competition. When open access to distribution wires begins, the competitive retail market will consist of electricity end-users with a monthly average peak demand of at least one MW for the preceding 12 months. After two years, the threshold level will be reduced to 750 KW and every year thereafter, ERC will gradually reduce the threshold level, as it sees fit, until it reaches the household demand level. EPIRA provides that the supply of electricity is not a public utility operation; as such, a supplier is not required to secure a national franchise. However, a license from the ERC is required. The prices to be charged by suppliers are not subject to regulation by the ERC. 2.6 Regulation At least four institutions have regulatory or oversight authority over the electricity industry, namely: the Joint Congressional Power Commission, ERC, DOE and the National Electrification Administration (NEA). Their functions are spelled out in EPIRA as follows: The Joint Congressional Power Commission (JCPC): sets the guidelines and overall framework to monitor and ensure the proper implementation of EPIRA; endorses privatization plans for approval by the President of the Philippines; ensures transparency in the conduct of public bidding procedures regarding privatization of NPC generation and transmission assets; reviews and evaluates the performance of industry participants in relation to the objectives and timelines set forth in EPIRA; and Final Report Page 13

35 determines inherent weaknesses in the law and recommend necessary remedial legislation or executive measures. (EPIRA, Sec. 62) Among the functions of the Department of Energy (DOE) are: to formulate energy policies and integrate energy programs of the Government; to develop the Power Development Plan for inclusion in the Philippine Energy Plan; to ensure the reliability, quality, and security of supply of electric power; to supervise the restructuring of the electricity industry; and to establish the Wholesale Electricity Spot Market and to formulate its rules of operation. (EPIRA, Sec. 37) The Energy Regulatory Commission (ERC) was created as an independent, quasi-judicial regulatory body mandated to promote competition, encourage market development, ensure customer choice, and penalize abuse of market power in the restructured electricity industry. Among its functions to accomplish these objectives are (EPIRA, Sec. 43): to enforce the implementing rules and regulations of EPIRA; to enforce the rules and regulations governing the operations of the electricity spot market and the activities of its participants; to establish and enforce a methodology for setting transmission and distribution wheeling rates and retail rates for the captive market of a distribution utility; to set a lifeline rate for the marginalized end-users; to monitor and to take measures to penalize abuse of market power, cartelization, and anti-competitive or discriminatory behavior by any electric power industry participant; to impose fines or penalties for any noncompliance with or breach of EPIRA, the Implementing Rules and Regulations (IRR) of EPIRA, and rules and regulations which it promulgates and administers; and to suspend the wholesale electricity spot market in case of national emergency. (EPIRA, Sec. 30) Finally, the National Electrification Administration (NEA) continues to be under the supervision of the Department of Energy (EPIRA, Sec. 58) but its franchising function has been transferred to Congress five years after EPIRA s effectivity (EPIRA, Sec. 27). It also acts as guarantor for purchases of electricity in the WESM by an electric cooperative or small distribution utility to support its credit standing (EPIRA, Sec. 30). Its additional mandates under EPIRA are (EPIRA, Sec. 58): to prepare electric cooperatives in operating and competing under the deregulated electricity market within five years from the effectivity of EPIRA, specifically in an environment of open access and retail wheeling; to strengthen the technical capability and financial viability of rural electric cooperatives; and to review and upgrade regulatory policies with a view to enhancing the viability of rural electric cooperatives as electric utilities. 3. Structure of Philippine Electricity Prices Among the five countries covered in this study, the Philippines has the most detailed unbundling of electricity tariffs. Singapore has also unbundled its rates but not as much as the Philippines. The unbundling of rates is one of the provisions in EPIRA. 12 Thus, the DUs are mandated to provide their customers an itemized listing of components that comprise the price charged to them. In addition, they are also required by the ERC to submit monthly Monitoring Rates Compliance Reports that itemize the price components with the 12 Sec. 36, Republic Act no. 9136: Electric Power Industry Reform Act of 2001 (EPIRA). Final Report Page 14

36 corresponding peso charges. The components of electricity price generally fall into the following categories: (i) generation, (ii) transmission, (iii) distribution, supply and metering; (iv) system loss, (v) subsidies; (vi) taxes and other levies. The next sections describe each component and the pertinent regulations governing their application. 3.1 Price Components Generation Charge The generation charge is the cost of energy purchased by the distributor from power generators through bilateral contracts or at WESM. This is a pass through cost, i.e., the DU can charge the full costs to its customers based on a formula prescribed by the ERC, as outlined in Article 2, Sections 1 and 2 of the ERC Resolution No. 16, Series of Bilateral contract prices are negotiated by the generator and its contracting distributor while WESM prices vary with the nodes where the distributor withdraws electricity. Thus, different distributors have different generation rates but each one has a uniform rate for all its customer classes. Transmission Charge The transmission charge is payment to the transmission company for the use of the transmission wires in transporting electricity from the generators to the distributors. It is regulated and reset every five years, based on performance-based price setting methodology laid out in the Rules for Setting the Transmission Wheeling Rates (RTWR). The monthly adjustment to transmission charge is outlined in Article 2, Section 3 of the ERC Resolution No. 16, Series of It has two components: system charge and demand charge. The former is priced in pesos per kilowatt-hour (Php/kWh) while the latter, per kilowatt (Php/kW), is based on peak demand. The demand charge applies only to commercial and industrial customer classes. Distribution Charge The distribution charge pays for the use of the distribution wires in transporting electricity from the distributors to the end-users. Under the present system, DUs also perform retail services such as billing and metering, but the charges for supply and metering are unbundled from distribution. DUs are subject to performance-based regulation. Their rates are determined based on the methodology set out in the Rules for Setting Distribution Wheeling Rates (RDWR) for PIOUs and in the Rules for Setting Electric Cooperatives Wheeling Rate (RSEC-WR) for ECs. The distribution charge consists of demand and system charges, while supply and metering each consists of retail and system charges. The demand charge and system charges are priced in pesos per kilowatt (Php/kW) and pesos per kilowatt-hour (Php/kWh), respectively, while the retail charges are monthly fixed prices. System Loss Charge The system loss charge pays for energy lost when electricity flows through the distribution wires as well as electricity lost due to theft. The extent that DUs can pass on this cost to consumers is stipulated in Republic Act 7832 (Anti-electricity and Electric Transmission Lines/Materials Pilferage Act), passed on 8 December Said law stipulated a cap on the level of loss that can be passed on to end-users: 8.5% of total electricity purchased for PIOUs and 14% for electric cooperatives. The monthly computation of system loss is provided for in Article 2, Section 4 of the ERC Resolution No. 16, Series of Final Report Page 15

37 Subsidies Subsidies consist of (i) lifeline rate subsidy, (ii) senior citizen subsidy, and (iii) interclass cross-subsidy. Lifeline rates are special prices for low-income customers mandated by law 13. The subsidy to recover the lifeline rates discounts is taken from the customers not qualified for the lifeline rates. The lifeline subsidy rate is specific to each distribution utility and is approved by the ERC. Each distribution utility applies a uniform subsidy rate on all classes of customers who pay for the subsidy. The rate is adjusted monthly based on computation stipulated by ERC and contained in Article 2, Section 5 of the ERC Resolution No. 16, Series of The senior citizen subsidy pays for the discounts given to senior citizens whose monthly electricity consumption does not exceed 100 kwh. The subsidy rate is calculated by the distribution utility according to a formula prescribed by the regulator and stipulated in ERC Resolution No. 23, Series of Interclass cross-subsidies have been phased-out since late 2006, but some DUs (MERALCO and MECO) are allowed to collect under-recovery for cross-subsidy that they had applied in previous years. Taxes and other Levies Included under taxes and other levies are: (i) value added tax (VAT), (ii) local franchise tax, (iii) business tax, (iv) energy tax, (v) universal charge; (vi) loan condonation; (vii) Incremental Currency Exchange Rate Adjustment (ICERA); and (viii) reinvestment fund for sustainable capital expenditures. The general rate for VAT is 12%. However, DUs obtain their electricity from a mix of generators some of whom use fuel whose outputs are VAT-exempt, e.g., geothermal, hydro and renewables. In these cases, the effective VAT rate on generation charge may be lower than 12%. Local franchise tax is imposed by the local government while energy tax is levied on residential customers whose monthly electricity consumption exceeds 600 kwh. As of April 2012, the universal charge 14 included in electricity bills consists of two items: an environmental charge for watershed rehabilitation and management, and a missionary electrification charge to support power generation and power delivery system in areas that are not connected to the transmission system. The environmental charge is fixed at P0.0025/kWh, while the missionary electrification charge is set by ERC from time to time. Both charges are applied uniformly on all customer classes. As of October 2012, the missionary electrification charge remained at P0.1136/kWh, which was set by ERC in August Additional universal charges are, however, forthcoming. PSALM has applied to ERC for a universal charge to cover for stranded debts and stranded contract costs since June The application is for P per kwh for stranded debts and P per kwh for stranded contract costs, to be collected over a 15- and 4-year period, respectively. The ERC has yet to render decision on the application. 13 Section 73. Lifeline Rate, EPIRA. 14 Section 34. Universal Charge, EPIRA. Final Report Page 16

38 Loan condonation 15 is the rate reduction enjoyed by customers of ECs on account of loans incurred by ECs that have been absorbed by PSALM. This transfer to PSALM of all outstanding financial obligations incurred by ECs for the purpose of financing rural electrification is provided for in EPIRA. ICERA 16 was adopted in 2003 as a mechanism for recovering (or refunding) the deferred incremental costs (or savings) incurred by NPC on foreign currency exchange fluctuations that affect its debt servicing. The pertinent loans were those approved by the previous regulator, ERB. As these loans were incurred by NPC in connection with the build-up of generation capacity, EPIRA stipulates that the costs of servicing these loans be passed on to electricity consumers, hence ICERA. The principle behind ICERA applies also to the reinvestment fund for sustainable capital expenditures (RFSC), previously called Members Contribution for Capital expenditure (MCC). RFSC is used to fund the amortization or servicing of debts incurred by ECs for the expansion, rehabilitation or upgrading of their existing electric power system in accordance with their respective capital expenditure plans approved by ERC Tariff Schedules of Selected DUs How the different price components affect end-user tariffs are shown in the next tables. Tariff schedules for most of 140 DUs were constructed based on the model case scenarios described in Table I.1. The model cases are: (i) residential customer with 200-kWh monthly consumption; (ii) commercial customer with 3-MWh monthly consumption; (iii) low voltage industrial customer with 50-MWh monthly consumption; and (iv) high voltage industrial customer with 200-MWh monthly consumption. The next four tables (Table II.8 to Table II.11) present the price schedules of selected DUs: two privately-owned, MERALCO and VECO; and seven ECs, one from each of the seven groups as defined by ERC 18 : KAELCO (Group A), SOLECO (Group B), BOHECO 2 (Group C), PANELCO 1 (Group D), DASURECO (Group E), PELCO 2 (Group F), and BATELEC 2 (Group G). Note that Table II.10 shows no computed tariff for low voltage industrial customers of SOLECO as there is no such class in its schedule. This is not unusual: a number of ECs do not have a schedule for either low or high voltage industrial customer or both. LUELCO, SAMELCO 1 and ANECO, for instance, have schedules for industrial customer connected to high voltage wires, but none to low voltage wires. Others, such as QUEZELCO 2, LEYECO 3 and NORSAMELCO, have schedules for low voltage industrial customer but none for high voltage customers. Indeed the price schedules reveal the different customer profiles of the DUs. But the wide variation in tariff levels for the same customer class is even more striking. Residential tariff for 200-kWh monthly consumption is P2,051 (P10.26 per kwh) for MERALCO customers, compared to only P1,328 (P6.64 per kwh) for DASURECO s. Tariffs range from P7.92 to P11.03 per kwh for 3-MWh commercial consumption; from P8.66 to P11.30 for 50-MWh low voltage industrial consumption; and from P6.89 to P10.56 per kwh for 200-MWh high voltage industrial consumption. 15 Sec. 60, Republic Act no. 9136: Electric Power Industry Reform Act of 2001 (EPIRA). 16 ERC Case No Rules for Setting Electric Cooperatives Wheeling Rates, Sep 23, Rules for Setting Electric Cooperatives Wheeling Rates, Sep 23, Final Report Page 17

39 Table II.8 Components of Residential Electricity Tariffs with 200-kWh Monthly Consumption of Selected DUs, July 2011 (values in Philippine peso) MERALCO VECO KAELCO SOLECO BOHECO 2 PANELCO 1 DASURECO PELCO 2 BATELEC 2 Generation Charge 1, , , , , Previous Power Cost Adjustment (6.28) - (4.88) - - Franchise & Benefits to Host Comm. Transmission System Charge Distribution System Charge Supply System Charge Supply Retail Customer Charge Metering System Charge Metering Retail Customer Charge System Loss Charge Lifeline Rate Subsidy Senior Citizen Subsidy Inter-class Cross-subsidy Power Act Reduction (1.86) (22.51) - (60.00) (38.14) (60.00) (60.00) - - Loan Condonation per kwh (29.96) - (8.38) - Local Franchise Tax Business Tax Generation VAT Transmission VAT System Loss VAT Distribution VAT Power Act Reduction VAT (0.01) (0.75) Others VAT Others VAT EVAT Other Charges Adjustment on Generation Cost Universal Charge - Missionary Electrification Charge Universal Charge - Environmental Charge Fuel Recovery Charge ICERA (1.30) Foreign Exchange Adjustment Reinvestment Fund/MCC Residential Tariff 2, , , , , , , , , Final Report Page 18

40 Table II.9 Components of Commercial Electricity Tariffs with 3-MWh Monthly Consumption of Selected DUs, July 2011 (values in Philippine peso) MERALCO VECO KAELCO SOLECO BOHECO 2 PANELCO 1 DASURECO PELCO 2 BATELEC 2 Generation Charge 15, , , , , , , , , Previous Power Cost Adjustment (94.20) - (73.20) - - Franchise & Benefits to Host Comm Transmission System Charge - 2, , , , , , , , Transmission Demand Charge 4, Distribution System Charge , , , , , , , , Distribution Demand Charge 4, Supply System Charge Supply Retail Customer Charge Metering System Charge - 1, Metering Retail Customer Charge System Loss Charge 1, , , , , , , , , System Loss Charge per kw Lifeline Rate Subsidy Senior Citizen Subsidy Inter-class Cross-subsidy Loan Condonation per kwh (30.60) - (35.10) - Loan Condonation per customer (2.69) Local Franchise Tax Business Tax Generation VAT 1, , , , Transmission VAT System Loss VAT Distribution VAT , Others VAT Others VAT EVAT , Other Charges Adjustment on Generation Cost UC - Missionary Electrification UC - Environmental Charge Fuel Recovery Charge ICERA (19.50) Foreign Exchange Adjustment Reinvestment Fund/MCC , Commercial Tariff 31, , , , , , , , , Final Report Page 19

41 Table II.10 Components of Low Voltage Industrial Electricity Tariffs with 50-MWh Monthly Consumption of Selected DUs, July 2011 (values in thousand Philippine pesos) MERALCO VECO KAELCO SOLECO BOHECO 2 PANELCO 1 DASURECO PELCO 2 BATELEC 2 Generation Charge Previous Power Cost Adj (1.57) - (1.22) - - Franchise & Benefits to HC Transmission System Charge Transmission Demand Charge Distribution System Charge Distribution Demand Charge Supply Retail Customer Charge Metering Retail Customer Charge System Loss Charge System Loss Charge per kw Lifeline Rate Subsidy Senior Citizen Subsidy Sr. Citizen Discount Charge Inter-class Cross-subsidy Loan Condonation per kwh Loan Condonation per customer (0.00) Local Franchise Tax Business Tax WESM VAT Generation VAT Transmission VAT System Loss VAT Distribution VAT Others VAT Others VAT EVAT Other Charges Adjustment on Generation Cost UC - Missionary Electrification UC - Environmental Charge Fuel Recovery Charge ICERA Foreign Exchange Adjustment Reinvestment Fund/MCC LV Commercial Tariff Final Report Page 20

42 Table II.11 Components of High Voltage Industrial Electricity Tariffs with 200-MWh Monthly Consumption of Selected DUs, July 2011 (values in Philippine peso) MERALCO VECO KAELCO SOLECO BOHECO 2 PANELCO 1 DASURECO PELCO 2 BATELEC 2 Generation Charge 1, , , , , Previous Power Cost Adjustment (6.28) - (4.88) - - Franchise & Benefits to Host Comm. Transmission System Charge Transmission Demand Charge Distribution System Charge Distribution Demand Charge Supply Retail Customer Charge Metering Retail Customer Charge System Loss Charge System Loss Charge per kw Lifeline Rate Subsidy Senior Citizen Subsidy Inter-class Cross-subsidy Loan Condonation per kwh Loan Condonation per customer (0.00) Local Franchise Tax Business Tax Generation VAT Transmission VAT System Loss VAT Distribution VAT Others VAT Others VAT EVAT Other Charges Adjustment on Generation Cost UC - Missionary Electrification Charge UC - Environmental Charge Fuel Recovery Charge ICERA (1.30) Foreign Exchange Adjustment Reinvestment Fund/MCC HV Commercial Tariff 1, , , , , , , , , Final Report Page 21

43 4. Trends in Philippine Electricity Tariffs The purpose of introducing competition in any market is to induce maximum efficiency from suppliers, remove economic rents, and allow consumers reap its benefits. EPIRA changed the market structure and regulation of the electricity industry for competition to thrive. Among the structural and regulatory changes that could be expected to have profound impact on tariffs are the (i) establishment of WESM; (ii) unbundling of transmission and distribution wheeling charges; (iii) removal of cross-subsidies; (iv) privatization of most generation capacity; (v) transfer of the management and control of state-owned power plants to the private sector; (vi) shift from rate of return base (RORB) regulation to performance-based regulation; and (vii) institution of universal charges and lifeline rate subsidy. Open access and retail competition are still in the pipeline but the market reforms are already substantial to bring competitive pressure on most service suppliers. As monopoly rents and inefficiencies are dissipated by competition and better regulation, prices are generally expected to fall. But market reforms can also move prices in opposite direction as subsidies are removed, rates rebalanced, and prices reflect actual costs of service. In this section, we examine in which direction prices have moved. To trace the movement in electricity prices, the tariffs in the four model cases are simulated from 2004 to 2011 using MERALCO s price schedules. MERALCO was chosen not only out of expediency since it is the only DU whose historical prices are readily available, but also because it represents more than three-fifths of total electricity sales. Consequently, the movement in MERALCO s prices can fairly represent the general movement in overall prices. Hereafter, related tariff elements are combined into major price components as shown in the next table. The component labeled temporary adjustments consists of price adjustments that relate to previous years (i.e., before 2011) costs. As such, it does not reflect the cost of service during It is distinguished from the other components so it can be easily taken out in subsequent analysis. Table II.12 Tariff Components Components Elements Generation Generation charge, Previous power cost adjustment, Franchise and benefits to host communities, Adjustment on generation cost, Fuel recovery charge, Automatic fuel recovery charge, GRAM, Foreign exchange adjustment Transmission Transmission demand charge, transmission system charge Distribution Distribution system charge, Distribution demand charge, Distribution system charge excess, Other fixed costs, Loan condonation (per kwh and per customer per month), Reinvestment fund/members capital contribution Supply Supply system charge, Supply retail customer charge, Supply charge per kw Metering Metering system charge, Metering retail customer charge, Metering retail customer charge CT rated, Metering retail customer charge Secondary, Metering retail customer charge Primary System loss System loss charge, System loss charge per kw Universal charge UC-Missionary electrification charge, UC-Environmental charge Subsidies Lifeline rate subsidy, Lifeline discount, Senior citizen subsidy, Senior citizen discount charge VAT 19 Generation VAT, Transmission VAT, System loss VAT, Distribution VAT, Power Act Reduction VAT, Others VAT, Others VAT 2, EVAT, WESM VAT, local franchise tax VAT Other taxes Local franchise tax, Business tax, Local and national franchise tax non-vat, Energy 19 At least 51 DUs have VAT on transmission indicated in their price schedules submitted to ERC. Final Report Page 22

44 Components Temporary adjustments Elements tax, Real Property tax, Tax Recovery Adjustment Cost, Franchise Tax ICERA, Inter-class cross-subsidy, Power Act Reduction, UC refund, Other refund, Other charges (CERA, discounts, recoveries) The simulations of residential, commercial and industrial tariffs using MERALCO s price schedules for various years are presented in Tables II.13 to II.16. The key findings are as follow: (i) During 2004 to 2011, tariffs for all customer classes increased faster than general consumer prices, resulting in real tariff increases. The average annual growth in nominal tariffs for the period were 8.73% for residential, 6.69% for commercial, 7.54% for low voltage industrial, and 6.92% for high voltage industrial. Since general consumer prices increased at an average annual rate of 4.79%, real residential tariffs increased by 3.76% annually, while the corresponding real changes in commercial, low voltage industrial and high voltage industrial tariffs were 1.81%, 2.62%, and 2.02%, respectively. (ii) The removal of inter- and intra-class subsidies 20 rebalanced the rates, raising residential more than industrial tariffs. In 2004, tariff per kwh was P5.70 for residential versus P5.83 for low voltage industrial, and P5.24 for high voltage industrial. Commercial tariff was highest at P6.87 per kwh. With the removal of subsidies, the tariff differential between residential and industrial widened as rates are aligned with costs. Thus, in 2011, tariff per kwh was P10.25 for residential, against P9.70 for low voltage industrial and P8.37 for high voltage industrial. Commercial tariffs remained the highest among customer classes at P10.81 per kwh. (iii) Besides the removal of subsidies, tariff increases were also caused by new taxes imposed on the sector. Value-added taxes (VAT) were first levied in 2006 and had been increasing since then. As of 2011, VAT accounts for more than 8% of tariffs across classes. (iv) After taxes, the next largest driver of tariff increases is distribution charge which increased at an average annual rate between 7.5% for residential and nearly 13% for low voltage industrial customers. This excludes increases in supply and metering which were accounted for separately due to tariff unbundling. Given the uniform application of market reforms, the prices of other DUs can only be expected to have moved in the same direction as MERALCO s. It is beyond the scope of this study to explain why electricity prices surged and defied general expectations. However, this provides context in later sections that compare Philippine electricity prices with those of other economies that have not undergone similar restructuring as the Philippine market. 20 The impact of the removal of intra-class subsidy was shown in the Phase I report where it was presented that the tariff for 100-kWh residential consumption increased by 6.7% annually, compared to 5.9% for 500-kWh residential consumption. Final Report Page 23

45 Table II.13 Electricity Tariff for MERALCO Residential Customers with 200-kWh Monthly Consumption (average of various years, values in Philippine pesos unless otherwise specified) Annual growth rate Generation , , Transmission Distribution Supply Metering System loss Temporary adjustments (158.47) (94.96) (39.76) (14.08) (18.92) (35.59) (2.73) (0.25) Universal charge Subsidy VAT Other taxes Tariff in current prices 1, , , , , , , , per kwh Tariff in 2000 prices , , , , , , , per kwh Share of: (in percent) Generation Transmission Distribution Supply Metering System loss Temporary adjustments (13.89) (6.46) (2.33) (0.82) (1.10) (2.14) (0.14) (0.01) Universal charge Subsidy VAT Other taxes Source: Authors calculation based on MERALCO s rates submitted to ERC. Final Report Page 24

46 Table II.14 Electricity Tariff for MERALCO Commercial Customers with 3-MWh Monthly Consumption (average of various years, values in Philippine pesos unless otherwise specified) Annual growth rate Generation 10,553 14,438 14,420 14,046 13,712 13,474 16,179 16, Transmission 3,840 3,546 4,004 4,492 4,707 4,188 4,332 4, Distribution 2,270 2,270 2,270 2,270 2,270 2,928 3,851 4, Supply Metering System loss 1,642 2,243 2,302 2,296 2,272 2,044 2,068 1, Temporary adjustments (312) Universal charge Subsidy VAT - - 2,336 2,453 2,517 2,214 2,655 2,664 Other taxes Tariff in current prices 20,613 24,478 27,127 27,086 27,028 26,152 31,137 32, per kwh Tariff in 2000 prices 16,321 18,295 19,432 18,667 17,248 15,995 18,490 18, per kwh Share of: (in percent) Generation Transmission Distribution Supply Metering System loss Temporary adjustments (1.19) Universal charge Subsidy VAT Other taxes Source: Authors calculation based on MERALCO s rates submitted to ERC. Final Report Page 25

47 Table II.15 Electricity Tariff for MERALCO Low Voltage Industrial Customers with 50-MWh Monthly Consumption (average of various years, values in thousand Philippine pesos unless otherwise specified) Annual growth rate Generation Transmission Distribution Supply Metering System loss Temporary adjustments (5.20) Universal charge Subsidy VAT Other taxes Tariff in current prices per kwh Tariff in 2000 prices per kwh Share of: (in percent) Generation Transmission Distribution Supply Metering System loss Temporary adjustments (1.34) Universal charge Subsidy VAT Other taxes Source: Authors calculation based on MERALCO s rates submitted to ERC. Final Report Page 26

48 Table II.16 Electricity Tariff for MERALCO High Voltage Industrial Customers with 200-MWh Monthly Consumption (average of various years, values in thousand Philippine pesos unless otherwise specified) Annual growth rate Generation , , Transmission Distribution Supply Metering System loss Temporary adjustments (20.81) Universal charge Subsidy VAT Other taxes Tariff in current prices 1, , , , , , , , per kwh Tariff in 2000 prices , per kwh Share of: (in percent) Generation Transmission Distribution Supply Metering System loss Temporary adjustments (1.57) Universal charge Subsidy VAT Other taxes Source: Authors calculation based on MERALCO s rates submitted to ERC. Final Report Page 27

49 5. Representative Philippine Electricity Prices Section 3 revealed the wide variation in tariffs among a small selection of DUs. On a larger set, the variations are even much more striking. The next table summarizes the tariffs during 2011 of all DUs presented in Annex II for the four model cases. Table II.17 Profile of Philippine Electricity Tariffs during 2011 (values in Philippine pesos) Residential Commercial LV Industrial HV Industrial No. of DUs Mean 1,839 24, ,745 1,551,219 Median 1,892 24, ,035 1,595,270 Minimum 1,100 14, , ,855 Maximum 2,605 33, ,852 2,144,522 Standard Deviation as percent of Mean per kwh Mean Median Minimum Maximum It is worth noting that the DUs included in the above profile for all customer segments are less than 140, the total number of DUs covered in this study. There are at least two reasons for this deficit. Foremost is the availability and reliability of price data, as explained below. Another is that not all DUs have all four customer segments represented by the model cases. Some DUs, for example, have no industrial customer segment in their respective pricing schedules; in this case, it is assumed that there are no industrial customers, or their number is insignificant in the franchise areas covered by these DUs. In other cases, the DUs have only one segment for industrial customers, in which case it is assumed that are all connected to low voltage wires. In all cases, the highest tariff is more than twice the lowest. Thus, residential tariffs range from P5.50 to P13.03 per kwh; commercial tariffs, from P4.72 to P11.04 per kwh; low voltage industrial tariffs, from P4.70 to P11.20 per kwh; and high-voltage industrial tariffs, from P4.66 to P10.72 per kwh. There is not much difference between the mean and median, suggesting that the tariffs are almost normally distributed within a customer class. While the tariffs are normally distributed, the sales of DUs are not. For example, whereas MERALCO accounted for 62.7% of total residential electricity sales in January 2011, PANELCO 1 s share was a mere 0.3%. Prices also vary by month as shown in the chart below where prices are indexed at January 2011 levels. These variations reflect seasonality in electricity demand, gyrations in supply of fuels for power generation, and conditions in transmission and distribution. But the pattern is different for each customer class. Residential tariffs are lowest in January, commercial tariffs in September, and industrial tariffs in February. Peak levels were reached in November for all, except high voltage industrial which occurred in December. Final Report Page 28

50 Figure II.1 Price Variations by Customer Class and Month in 2011 (January 2011 prices = 1.00) Residential Commercial LV Industrial HV Industrial In light of the foregoing, what could be a representative price for the Philippines? Clearly, it cannot be just the price of one or selected DUs even if they account for substantial proportion of electricity sales. Using MERALCO s rates or the average of the largest x distributors to represent Philippine tariffs is inappropriate since it does not capture the real profile of tariffs. The choice of month matters also because of monthly variations in demand and prices of fuel supply. A proper statistical representation of a heterogeneous population should take account of these nuances. Accordingly, the representative price should include even prices of DUs whose sales comprise a small portion of the total, and it should not be for a single month in a year. The more variable the actual prices are across DUs and months, the more DUs and longer period should be included in the calculation of the representative price. It is conceivable to use the prices of all DUs for all months as these are regulated, submitted to the regulator, and should therefore be publicly available. In practice, however, not all DU price schedules are accessible, and those available may not be consistent across sources. There are four possible sources of price schedules, namely: the monthly Monitoring and Compliance (MC) schedules, submitted by DUs to ERC in hard copies 21 ; the ERC s database, maintained by the Investigation and Enforcement Division (IED) and purportedly culled from monthly submissions of DUs; Annual Report (AR) submissions of DUs to ERC (in soft copies); and DU website but only for a few private investor-owned. It turned out that there are discrepancies in the data from these different sources. A few detailed examples illustrate the difficulty of picking one source and reconciling data across sources. The IED database indicates zero generation rate for ZAMSURECO II, but its MC shows otherwise. The value-added tax (VAT) in the IED database of LEYECO III is 12% of generation rate of P4.0821/kWh, or P0.4898/kWh, whereas, the AR shows the VAT charge on generation to be P0.1165/kWh. Since the MC schedules are attested to by the DUs and approved by ERC, it is reasonable to assume that they are more reliable than the AR or IED database. And yet some figures appearing in the MCs can be questioned as well. BOHECO II s MC specify the VAT rates applying to distribution system and demand charges at and percent, 21 Beginning January 2012, DUs are required to make soft and hard copy submission of MCs using a uniform reportorial template prescribed by the regulator. This should improve the quality, if not availability, of price data. Final Report Page 29

51 respectively, while 1,221 percent for metering retail customer charge. These numbers are clearly off the mark since VAT is capped at 12%. Of these four sources, the MC schedules is regarded official, since they are prepared by the DUs and legally attested to by their responsible officers. Hence, whenever MCs are available, they are deemed authoritative unless the figures appear patently wrong, e.g., a VAT rate of more than 12%. Where the MC schedule is not available, the data in the AR is considered next reliable. When the MC and AR are both not available, the IED data is used, but only if the figures appear reasonable; otherwise, they are discarded. Hence, some data found in the MC or AR or IED that do not seem reasonable or reliable are excluded. From the available and reasonably reliable data, we constructed an average price, weighted by the monthly electricity sales of respective DUs, hereon referred to as composite price (CP). In all, the calculated composite prices represent 88.5% of electricity sales to residential customers during 2011, 87.5% for commercial, and 78.5% for industrial. Table II.18 Representativeness of Computed Composite Prices PCEP No. of data points used* Quantity included (GWh) Total quantity sold, 2011 (GWh) % of total sales represented Residential 1,029 16,548 18, Commercial 1,020 14,541 16, Industrial** 1,482 15,171 19, Total 46,260 56, * Refer to price-quantity pairs **LV and HV Industrial combined. 5.1 Composite Price The next table shows the computed composite prices for the four model cases representing residential, commercial, low voltage and high voltage industrial tariffs. These are averages of tariffs presented in Annex III, weighted by actual quantities of monthly electricity sales. Table II.19 Composite Prices by Customer Class and Region (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 1, , , Luzon 2, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , Final Report Page 30

52 Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) CARAGA 1, , , Mindanao 1, , , All regions 1, , , The composite price for residential consumer with 200 kwh monthly consumption during 2011 was P1,944 (P9.72 per kwh); for commercial consumer with 3 MWh consumption, P30,253 (P10.08 per kwh); for low voltage industrial consumer with 50 MWh consumption, P447,114 (P8.94 per kwh); and for high voltage industrial consumer with 200 MWh consumption, P1,617,028 (P8.09 per kwh). Residential tariffs are higher on a per kwh basis compared to industrial as would be expected if tariffs reflect the costs of service. Prices differ widely across regions as is evident from Table II.19, with rates generally highest in Luzon and lowest in Mindanao. For residential tariffs, Region IVB had the highest rate (P2, or P10.82 per kwh), which was nearly twice the lowest imposed in the CARAGA region (P1, or P5.50 per kwh). NCR had the highest commercial rate, P32,448 (P10.88 per kwh), nearly twice the average rate in Region XII, P18,464 (P6.15 per kwh). The highest high voltage industrial tariff was charged in Region II at P10.39 per kwh, in contrast to the lowest rate imposed in Region XII at P5.27 per kwh. But for low voltage industrial tariffs, Region VI in Visayas had the highest rate at P9.92 per kwh, although the lowest rate was still in Mindanao, specifically Region XII at P5.75 per kwh. Despite supply problems encountered in 2011, tariffs were still substantially lower in Mindanao than in the two other major islands. The average tariff per kwh in Mindanao was P6.70, compared to P9.46 in Visayas and P10.13 in Luzon, for residential customers. This pattern holds up in other customer classes too. 5.2 Base Composite Price The calculated composite prices in the preceding section included tariff elements that are provisional to the extent that they represent adjustments to past years costs or are provided for in some law or regulation to be assessed only for a limited period. These elements may raise or lower rates but only in the interim, and therefore should be considered noise or distortion. For example, MERALCO s tariffs in 2011 included an adjustment for underrecovery of inter-class cross-subsidy that it implemented from June 2003 to October In 2007, the ERC allowed MERALCO to raise their tariffs by as much as the unrecovered subsidy amounting to more than one billion pesos, or equivalent to P per kwh, from that time until amount is fully recovered. 22 The ERC also directed MERALCO to refund P3.9 billion or P per kwh to its customers, representing the excess that it collected when it applied the CERA from June 2003 to October The adjustments for under recovery and refund will discontinue as soon as the pertinent amounts have been fully accounted for. In addition, during 2011, about 80 DUs were still implementing the mandated rate reduction, more popularly known as Power Act Reduction (PAR). Section 72 of EPIRA provides that the obligation of a DU to provide Php0.30/kWh discount ceases when the Transition Supply Contract (TSC) between NPC and successor generating company expires, even if the DU continues to be supplied by the successor generating company. Some of the TSCs have already expired, hence only 80 DUs implemented the discounts in By excluding these transitory elements, the adjusted composite prices reflect the actual and current costs of providing electricity. Accordingly, the following are removed from the composite prices: (i) interclass cross-subsidy; (ii) mandated rate reduction or PAR; (iii) 22 ERC Case No RC. Final Report Page 31

53 incremental current exchange rate adjustment (ICERA); (iii) refunds for universal and other past charges; (iv) other charges, discounts, recoveries and currency exchange rate adjustment (CERA). Not all DUs are however affected by this adjustment. Table II.20 DUs with Transitory Elements in their Price Schedules in 2011 Element Distribution Utilities Interclass MERALCO, MECO cross-subsidy PAR MERALCO, LUECO, BLCI, MECO, VECO, CEPALCO, DLPC, COLIGHT, ILPI, CEDC, LASURECO, ABRECO, BENECO, BISELCO, PANELCO 1, PELCO 1, BATELEC 1, LUBELCO, OMECO, ORMECO, MARELCO, TIELCO, CANORECO, CASURECO 1, CASURECO 3, FICELCO, MASELCO, VRESCO, TISELCO, CENECO, ILECO 2, ILECO 3, NOCECO, PROSIELCO, CEBECO 1, CEBECO 2, CELCO, NORECO 2, SOLECO, BILECO, DORELCO, ESAMELCO, LEYECO 2, LEYECO 3, LEYECO 4, LEYECO 5, NORSAMELCO, SAMELCO 1, SAMELCO 2, ZAMSURECO 1, ZAMSURECO 2, ZANECO, CAMELCO, FIBECO, MOELCI 1, MOELCI 2, DORECO, COTELCO, LANECO, SOCOTECO 1, SOCOTECO 2, SUKELCO, ANECO, ASELCO, DIELCO, SIARELCO, SURNECO, BUSECO, SURSECO 1, SURSECO 2, DANECO, DASURECO, ZAMCELCO, SIASELCO, BASELCO, FLECO, MORESCO 2, PALECO, QUEZELCO 1, ROMELCO ICERA MERALCO, VECO, CEDC, IFELCO, QUIRELCO, AKELCO, GUIMELCO, ILECO 2, CEBECO 2, SOLECO, ESAMELCO, LEYECO 4, SAMELCO 1, SAMELCO 2, FIBECO, SOCOTECO 2, DASURECO, FLECO Refunds BENECO, ISELCO 1, ZAMECO 2, BOHECO 1, BANELCO, ZANECO, MOELCI 2, ANECO, ASELCO, ZAMCELCO, ANTECO Other charges, discounts, recoveries and CERA TEI, VECO, PANELCO 1 The adjustments for these components resulted in prices shown in Table II.21. These are referred hereon as base composite prices. These prices represent Philippine retail tariffs in the benchmarking exercise with other ASEAN countries in Section IV. All policy simulations in Section V are also referenced to these prices. Table II.21 Base Composite Prices by Customer Class and Region (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 1, , , Luzon 2, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , Final Report Page 32

54 Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , The transitory elements generally lowered residential tariffs and increased commercial and industrial tariffs. As a result, the base composite prices are generally higher for residential, but lower for commercial and industrial customers than the corresponding composite prices. The differences are however small but nonetheless vary across DUs and customer classes. Table II.22 Impact of Removing Transitory Elements from Composite Prices (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR CAR I II III IVA IVB V Luzon VI VII VIII Visayas IX X XI XII ARMM CARAGA Mindanao All regions Pre-tax Base Composite Price The analysis of changes in MERALCO tariffs in the preceding section underscores the significance of taxes, particularly value-added, in driving prices up. Removing all taxes (national and local) from retail prices serves two purposes in this study. One is to obtain prices that can be compared with those of other countries included in this study. Tariffs are compared at pre-tax, not actual, retail levels since the primary objective is to compare approximate costs of supplying electricity. The other purpose is to estimate the impact of taxes on retail prices. Since different taxes are levied at different components of retail price and stages of electricity production, determining how much tax is actually imposed on the sector is not straightforward. The base composite prices after removing all taxes are presented below. Final Report Page 33

55 Table II.23 Pre-tax Base Composite Prices by Customer Class and Region (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 1, , , CAR 1, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 1, , V 1, , , Luzon 1, , , VI 1, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , Comparing prices in Tables II.21 and II.23, the effective tax rates applied to different customer classes across regions are estimated between 2% and 26%. 23 Overall, residential consumers tend to bear more taxes than other customer classes. The effective tax rate on residential customers was 9.26%, against 9.05% on commercial, 8.71% on low voltage industrial, and 8.77% on high voltage industrial. Between major islands, the tax rate differentials are more significant. Customers in Luzon are assessed higher taxes than their counterparts in Visayas and Mindanao. Among residential customers, for example, the effective rates were 9.7%, 7.6% and 6.2% in Luzon, Visayas and Mindanao respectively. Customers in Region IVB paid the highest rates, whereas those in Region VIII paid the least. Table II.24 Percent Decline in Base Composite Prices after Removing All Taxes (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR CAR I II III IVA IVB V Luzon VI VII VIII This rate refers to taxes assessed on LASURECO (ARMM). The data was obtained from its annual report. Final Report Page 34

56 Residential Low voltage Commercial Low voltage Industrial High voltage Industrial Visayas IX X XI XII ARMM CARAGA Mindanao All regions Much of these tax differences are due to incentives afforded to users of renewable energy since power generated from renewables is VAT-exempt. Consequently, localities that source more power from renewables such as Mindanao (hydro) and Visayas (geothermal) are levied lower taxes. 5.4 Impact of MERALCO on Composite Price MERALCO is the single largest DU accounting for about three-fifths of total electricity sales in Without doubt, MERALCO s prices can significantly affect the average prices because of its sheer weight. The next table shows average prices calculated with and without MERALCO. Table II.25 MERALCO and Composite Prices (in Philippine peso) Base Composite Price Pre-tax Base Composite Price Composite Price RESIDENTIAL MERALCO 2, , , Weighted average 1, , , without MERALCO Weighted average 1, , , with MERALCO LV COMMERCIAL MERALCO 32, , , Weighted average 23, , , without MERALCO Weighted average 30, , , with MERALCO LV INDUSTRIAL MERALCO Weighted average without MERALCO Weighted average with MERALCO HV INDUSTRIAL MERALCO 1, , , Weighted average 1, , , without MERALCO Weighted average 1, , , with MERALCO Final Report Page 35

57 Since MERALCO s prices are higher than average in all customer classes, their inclusion is expected to pull up the composite prices. The extent it is able to do that depends on the customer segment. MERALCO pulled up the composite price for the residential class by 10%; for commercial class by 26%; for the low voltage industrial class by 11%; and for the high voltage industrial class by 6%. But MERALCO is also assessed higher taxes than average. This can be seen from Table II.24 where the effective tax rates in NCR are higher than average in all customer classes. Thus, the effect of including MERALCO s prices on pre-tax base composite prices is lower, i.e., 7% for residential, 24% for commercial, 10% for low voltage industrial, and 4% for high voltage industrial. 6. Key Issues Affecting Philippine Electricity Prices A number of policy issues are perceived to be affecting electricity prices. Some of these issues are dealt with in Section V. Below, issues impacting generating costs are discussed. A separate discussion of these issues shed light on the variability of tariffs, noted in the previous section, and on some suggested measures to help lower electricity prices. 6.1 Wholesale Electricity Spot Market Competition in generation was introduced by creating the WESM 24, an auction market for the bulk trading of electricity where generators compete to sell electricity in a centralized pool and distributors and bulk consumers buy from the pool. The market is organized as a mandatory pool (also called a gross pool) which means that all generators are required to sell all their electricity outputs in the pool and all buyers of electricity buy from the pool. This market design allows financial bilateral contracts between buyers and sellers as hedges against the volatility of the spot price outcomes but the physical flows of power are all within the pool. The trading participants include sellers (generating companies) and buyers or customers (distribution utilities, bulk consumers, wholesale aggregators). All generating companies with facilities connected to the transmission or distribution systems and all customers purchasing electricity supplied through the transmission system have to register as pool members. Generators compete to supply electricity by submitting price-quantity offers indicating the amount of electricity they are willing to generate at various prices during a trading period. The Market Operator (MO) forecasts the total load for the trading period and determines the least-cost dispatch schedule that meets the forecasted load, while taking into account the system conditions and security requirements. This procedure, which is executed by the Market Dispatch Optimization Model, produces the dispatch schedule along with the prices at the nodes, called the locational marginal price (LMP). The Market Operator (MO) oversees the hourly trading activities in the market. He receives offers from the sellers and demand bids from the buyers (in case there is demand-side bidding) or forecasts the total quantity demanded or load. Next he draws up a dispatch schedule, a list of generating units together with the amount of electricity in MW that each unit should inject into the grid at specified time periods. He then transmits the dispatch schedule to the System Operator for implementation. The MO also facilitates the settlement of payments for the market transactions and other payments such as market fees and line rentals. The System Operator (SO) is responsible for the operation and control of the grid: executes the dispatch schedule drawn up by the MO, ensures real-time balancing between generation and consumption (load), and maintains the reliability of the transmission grid by procuring 24 Sec. 30, Electric Power Industry Reform Act (EPIRA) of 2001 Final Report Page 36

58 ancillary services as required. (Regulatory approval for including reserves in the spot market is still pending. When reserves are traded in the spot market, the principle of co-optimization will be applied.) Supply-Demand Conditions Drive Spot Price Figure II.2 shows the movement of monthly spot market price as measured by the Effective Selling Price (ESP) at WESM. It shows a downward trend in spot price from the start of WESM operations in July 2006 up to December 2009, averaging roughly PhP91/MWh per month, but climbed steeply to its highest level in March The high prices were attributed to tight supply-demand conditions and transmission constraints. 25 These price movements are reflected in the generation charge to the consumer as we see in the next section. Figure II.2 Monthly Spot Market Price: July 2006 December 2010 (in Philippine peso) Source: 19 th EPIRA Implementation Report, Department of Energy. For convenience, we refer to the period from July 2006 to December 2009 as Period I and the period from January 2010 to December 2010 as Period II. It turns out that period II had a generally tighter EXSUP (defined as average offers less average demand) than period I: excess supply averaged 1,096 MW in period I but only 761 MW in period II. The relationship between the spot market price (ESP) and excess supply (EXSUP) is shown in the scatterplot in Figure II.3 where excess supply falls as spot price increases. The negative relationship between spot price and excess supply follows from the fact that the latter is a measure of scarcity. 25 WESM Market Report for Jan 2009 Jun 2010 Final Report Page 37

59 Challenges in Pricing Electric Power Services in Selected ASEAN Countries Figure II.3 Spot Price (ESP) vs Excess Supply (EXSUP): WESM, Jun 2006 Dec 2010 (in Philippine peso) exsup esp Fitted values A simple regression that quantifies this relationship is given in Table II.26. The equation was estimated by the Prais-Winsten procedure to correct for serial correlation without losing an observation. The line shown in Figure II.3 is the estimated regression on line. Table II.26 Regression of Spot Price (ESP) against Excess Supply (EXSUP) Final Report Page 38

60 The estimated equation in the preceding table is given below, confirming the negative relationship between spot price and excess supply: In addition to scarcity conditions, spot price may be pushed up during peak demand when supply is tight so that the more-expensive-to-operate generators have to be dispatched. Moreover, the potential to exercise of market power during this time is greater and pivotal suppliers are encouraged to raise their price offers. This is confirmed by the results of the regression of spot price (ESP) on the variables excess supply (EXSUP) and peak demand (PEAKDEM) shown in Table II.27. PEAKDEM has the expected positive sign and is significant. Table II.27 Regression of Spot Price on Excess Supply and Peak Demand The elasticities at the means of spot price (ESP) with respect to excess supply (EXSUP) and peak demand (PEAKDEM) are shown in the next table. The elasticity of ESP with respect of EXSUP is 1.014, suggesting that a 10% increase in excess supply could reduce spot price by 10.14%. 26 On the other hand, a 10% reduction in peak demand could slash spot price by 20.02%. This latter result points to the desirability of demand response programs (e.g., timeof-use rates) that can reduce peak demand. 26 A similar result was reported in the Singapore market where a 10% increase in supply cushion leads to a 6.5% decrease in the USEP, (Market Surveillance & Compliance Panel Annual Report 2011, National Electricity Market of Singapore). Supply cushion is conceptually equivalent to excess supply defined in this study. Final Report Page 39

61 Table II.28 Elasticity of WESM Spot Price with respect to Excess Supply and Peak Demand Notes: The elasticities at the mean are given in the column headed by ey/ex. The means of the regressors are given in the column headed by x. Spot Prices and Bilateral Contracts The WESM allows the direct sale of electricity bilaterally between a seller and a buyer. While the quantity and price are negotiated outside WESM, it does not involve the physical flow of electricity from seller to buyer outside the spot market. The bid-based process of the spot market is used to ensure that the System Operator would have continuous oversight of the total power flow in the transmission system in order to guarantee the integrity of the power system. This is why all electricity output of generators must go through the WESM including those covered by bilateral contracts. However, trading participants have the option of settling quantities under bilateral contracts directly with their contracting parties. Bilateral contracts between buyers and sellers specify quantities and prices of electricity in advance. As a hedge against spot market price volatility, these contracts are usually contracts for differences (CfDs). If the spot price is higher than the contract price, the seller pays the buyer the difference; if the spot price is lower than the contract price, the seller collects the difference from the buyer. In the first month of trading at WESM, the bilateral contracts quantity (BCQ) was 56% of the total electricity traded (see Figure II.4). Within six months, the BCQ share jumped to 83% and remained above 80% except in January and February 2009 when the BCQ shares were 79% and 77%, respectively. In the first ten months of 2011, the monthly BCQ shares breached the 90% mark seven times and in the other three months the shares were 89% and 90%. The highest BCQ share occurred in April 2011 at 95%. This is probably explained by the fact that five years after the establishment of WESM, the distributors were free of the requirement to source no more than 90% of their energy purchases through bilateral contracts 27. Thus, the wholesale electricity market is dominated by bilateral contracts. This means that the wholesale price of electricity is heavily weighted by the prices agreed in these contracts. 27 Sec. 45(c), EPIRA. Final Report Page 40

62 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Challenges in Pricing Electric Power Services in Selected ASEAN Countries Figure II.4 Bilateral Contracts Quantity vs Spot Market Quantity 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% BCQ(%) SMQ(%) Source of data: 19 th Status Report on EPIRA Implementation, DOE Effect of the Spot Price on End-Customer Price The main focus in this section is to examine how the wholesale spot price and its movements are reflected in the consumer electricity price. Since retail competition is not yet in place, the components of consumer price other than generation charge are regulated. Thus, the effect of spot price on consumer electricity price works its way through the generation price charged on the consumer. Now, generation cost is the largest component of the consumer bill (as can gleaned from Tables II.13 to II.16) and the generation cost is a mix of spot market and bilateral contracts costs. MERALCO Generation Price The available data on consumer generation price is a monthly series calculated by MERALCO for its customers. MERALCO computes the generation price as a weighted average of the various prices from its sources of energy with volume shares as weights. MERALCO s major sources of energy during the period January 2008 to June include the National Power Corporation (NPC), the Wholesale Electricity Spot Market (WESM) and Independent Power Producers (IPPs). The percentage share of the generation cost by major energy source is shown in Figure II.5. For example, in January 2009, the generation cost shares were: IPPs 48%, NPC 30% and WESM 22%. In April 2010, the shares were: IPPs 42%, NPC 28% and WESM 30%. A larger WESM cost share is usually caused by a high spot price. 28 The period January 2008 June 2012 was chosen because the data series is unbroken. Final Report Page 41

63 Price per kwh Jan-08 Mar-08 May-08 Jul-08 Sep-08 Nov-08 Jan-09 Mar-09 May-09 Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Challenges in Pricing Electric Power Services in Selected ASEAN Countries Figure II.5 Share in MERALCO s Monthly Generation Charge: Major Energy Sources ipps npc wesm Let WESMPRICE denote MERALCO s average generation cost obtained by dividing total payments to WESM by kwh purchased from WESM. This should not be confused with the spot price which is the Effective Selling Price (ESP); however, they should be correlated. Indeed, their graphs show that they move together (Figure II.6). We also define NPCPRICE and IPPSPRICE in the same way as WESMPRICE. Figure II.6 ESP and WESMPRICE ESP WESMPRICE To examine the effect of the spot price on the generation price in MERALCO s franchise area, we follow the calculations of the average monthly generation cost per kwh on MERALCO s website. First, we compare WESMPRICE with IPPSPRICE 29 and NPCPRICE (Figure II.7). We note that IPPSPRICE and NPCPRICE have almost the same orders of magnitude and are practically flat over the period. On the other hand, WESMPRICE is more volatile and has been generally lower than IPPSPRICE and NPCPRICE from January 2008 to December 2009 (period A) but were much higher from January 2010 to June 2012 (period B). Clearly, the effects of WESMPRICE differ in these two periods. We, therefore, examine the WESMPRICE in these two periods separately and then look at it for the entire period. 29 The IPPSPRICE is the weighted average of the prices of the three IPPs with which MERALCO has bilateral contracts: Quezon Power Philippines (Limited), San Lorenzo Natural Gas Power Plant, and Sta. Rita Natural Gas Power Plant. Final Report Page 42

64 Jan-08 Mar-08 May-08 Jul-08 Sep-08 Nov-08 Jan-09 Mar-09 May-09 Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Challenges in Pricing Electric Power Services in Selected ASEAN Countries Figure II.7 Generation Prices of MERALCO s Sources of Energy (PhP/kWh) wesm ipps npc Source: Based on MERALCO s generation charge, MERALCO website. Table II.29 summarizes the means and standard deviations of the three generation prices for the periods A and B as well as for the entire period. Also included are the mean and standard deviation of the overall generation price (GPRICE). As seen in period A, WESMPRICE has the smallest mean; thus, WESMPRICE helped to pull down the generation price. On the other hand, the opposite is true in period B; WESMPRICE helped to pull up the generation price. Thus, there are episodes when WESMPRICE is lower than bilateral contract prices and there are episodes when it is higher. But on the whole, WESMPRICE pulled the generation price upward as seen in the Entire Period column in Table II.29. In fact, during the entire period, WESMPRICE is higher than IPPSPRICE 61% of the time. Table II.29 Means and Standard Deviations of Generation Prices Jan 2008 Dec 2009 (Period A) Jan 2010 Jun 2012 (Period B) Jan 2008 Jun 2012 (Entire Period) Price Mean Std Dev Mean Std Dev Mean Std Dev WESMPRICE NPCPRICE IPPSPRICE GPRICE* *GPRICE = overall average generation price To sum up, spot market prices were generally declining during the period July 2006 to December 2009 but had a sharp change in direction in the first quarter of 2010 reaching its highest level in March Two factors tracked these price movements well, namely excess supply and peak demand. The data show that a 10% reduction in peak demand could slash spot price by 20%. This result points to the desirability of demand response programs that induce consumers to shift the consumption of energy to off-peak hours. The wholesale electricity spot price affects consumer electricity price through the generation price that consumers are charged. The data 30 show that the effects are mixed, i.e., in one period, spot price helped to pull consumer generation price downward but in another period, 30 The data refer only to MERALCO. Final Report Page 43

65 it helped to push generation price upward. Of course, another way of looking at this is to say that bilateral contract prices helped to dampen the volatility of the spot price. 6.2 Pricing of Bilateral Contracts Of the total quantity traded in WESM during 2011, the proportion settled at bilateral contract prices (rather than spot market prices) ranged from 88% (December 2011) to 95% (April 2011). Undoubtedly, the generation component is largely influenced by prices stipulated in bilateral contracts entered into by generation companies and DUs. As these contracts are commercially negotiated by the parties involved, the terms of the agreements vary. This is evident from a sample of contracts shown in Table II.30. In some contracts, stipulated prices are differentiated by day and time of use; in others, they are not. Some contracts provide a detailed basis of the stipulated price; others do not. Factors that trigger adjustments in contracted prices vary, but whatever the basis, they are meant to reflect changes in fuel prices. Final Report Page 44

66 Table II.30 Salient Features of Selected Bilateral Contracts Contract 1 Contract 2 Contract 3 Contract 4 Contract 5 Seller SMEC (San Miguel Energy Corporation), Independent Power Producer Administrator (IPPA) of the Sual Coal-Fired Power Plant KSPC (KEPCO SPC Power Corporation), generation company (Cebu Power Plant) APRI (AP Renewables, Inc.), generation company (Tiwi Geothermal Power Plant); renewable energy source no VAT GCGI (Green Core Geothermal Incorporated); generation company (Palinpinon Geothermal Power Plant and Tongonan TMI (Therma Marine Incorporated) Type of plant; installed capacity Coal-fired; 1,294 MW Circulating fluidized bed combustor boiler coal-fired base load; 200 MW Geothermal; 289 MW Geothermal Power Plant) Condensing-type geothermal base load; MW (Palinpinon) and MW (Tongonan); geothermal steam supplied by EDC (Energy Development Corporation) Non-propelled type barges (diesel engine); 200 MW Buyer TARELCO II (Tarlac II Electric Cooperative) LEYECO II (Leyte II Electric Cooperative) ALECO (Albay Electric Cooperative) AKELCO (Aklan Electric Cooperative) DLPC (Davao Light and Power Company) Type of agreement Electric power purchase agreement (EPPA), Power supply contract (PSC) Power supply agreement (PSA) Power supply agreement (PSA) Energy supply agreement (ESA) Energy supply contract (ESC) ERC approval date 18 October August August May May 2011 Contract term 2 years + 1 year automatic renewal upon due notice 10 years 3 years 10 years; provisions for early termination 3 years; provisions for early termination Contracted capacity/energy (monthly) Demand: MW Energy: MWh, average 84% of forecasted 43,800,000 kwh; take or pay MWh; 40% of energy requirement of ALECO Maximum demand: 10 MW Energy: MWh 15 MW; energy supply only for the hours load of TARELCO II Fuel price indexation Newcastle coal Newcastle coal Marine Diesel Oil Newcastle coal CPI; GCGI absorbs the risk of potential increases in geothermal steam cost Actual cost of fuel oil, lube oil and related fuel; with efficiency caps on heavy fuel oil and lube oil consumption rates Final Report Page 45

67 Although prices of generated power are not subjected to the same regulation on charges imposed by DUs on their captive markets, the ERC is mandated to review the power supply agreements entered into by the DUs and generation companies. This is to ensure that the agreed rates are reasonable as these are costs passed on to consumers. The regulator also deems it fit to ensure that the approved generation rates are sufficient for utilities to recover their costs and earn reasonable returns on invested capital. Hence, even the reasonableness of the weighted average cost of capital (WACC) imputed on the contracted price is evaluated by ERC. 6.3 Incentives for Indigenous Fuel Fossil Fuels Much of the available policy incentives on energy are designed more to encourage the discovery and development of supply than to reduce the energy prices paid by end-users. For example, the Service Contract System for oil exploration, contained in Presidential Decree No. 87, titled Oil Exploration and Development Act of 1972, provides incentives for harnessing sources of energy. These incentives are considered instrumental in the discovery of Nido oilfields in Northwest Palawan, offshore gas field in Malampaya, and onshore San Antonio gas field in northern Luzon. Investment incentives for coal exploration, development and production are also available. The next table lists the current incentives for harnessing oil, natural gas and coal, geothermal and mini-hydro resources. Final Report Page 46

68 Table II.31 Incentives Available for the Development of Fossil Fuels Incentives Oil and Natural Gas Coal Geothermal* 1 Service fee of up to 40% of net production Service fee of up to 40% of net proceeds Special privilege tax rates Tax payable by developers/grantees to develop potential sites for hydroelectric power and to generate, transmit and sell electric power shall be 2% of their gross receipts 2 Cost reimbursement of up to 70% gross production with carry-forward of unrecovered costs Recovery of operating expenses not exceeding 90% of the gross income after deducting all operating expenses Recovery of operating expenses not exceeding 90% of the gross value in any year with carry-forward of unrecovered cost 3 FPIA grants of up to 7.5% of the gross proceeds for service contract with minimum Filipino company participation of 15% 4 Exemption from all taxes except income tax VAT exemption Exemption from payment of VAT on gross receipts derived from sale of electric power whether wheeled via the NPC grid or electric utility lines 5 Income tax obligation paid out of government s share Income tax holiday for seven (7) years from start of commercial operations 6 Exemption from all taxes and duties for importation of materials and equipment for petroleum operations Exemption from payment of tariff duties and compensating tax on importation of machinery/equipment/spare parts/materials required for coal operations Exemption from payment of tariff duties and compensating tax on importation of machinery/equipment/spare parts/materials required for geothermal operations Tax and duty free importation of machinery, equipment and materials Exemption from payment of tariff duties and value-added tax (VAT) on importation of machinery and equipment within seven (7) years from date of awarding of contract 7 Depreciation of capital equipment over a ten-year period Tax credit on domestic capital equipment For developers who buy machinery, equipment, materials and parts from a local manufacturer, tax credit is given equivalent to 100% of the value of VAT and custom duties that would have been paid to import said machinery, equipment, etc. Special realty tax rates on equipment and machinery Realty and other taxes on civil works, equipment, machinery and other improvements of a registered mini-hydroelectric power Mini- Hydro* Final Report Page 47

69 Incentives Oil and Natural Gas Coal Geothermal* developer shall not exceed 2.5% of their original cost 8 Easy repatriation of investments and profits Easy repatriation of capital investments and remittance of earnings 9 Free market determination of crude oil prices, i.e., prices realized in a transaction between independent persons dealing at arms-length 10 Special income tax of 8% of gross Philippine income for subcontractors 11 Special income tax of 15% of Philippine income for foreign employees of service contractors and subcontractors Allow entry of alien technical personnel 12 The right of ingress to and egress from the coal operating contract (COC) area * Before the passage of the Renewable Energy Act of Sources: Presidential Decree (P.D.) 87: Oil Exploration and Development Act of 1972 (oil and natural gas), PD 972, PD 1174 (coal), PD 1442: An Act to Promote the Exploration and Development of Geothermal Resources (geothermal), and Republic Act No 7156: Mini-Hydro Law (mini-hydro). Mini- Hydro* Final Report Page 48

70 New and Renewable Energy Sources The passage of the Renewable Energy Act of 2008 represents a policy shift from incentivizing the development of any energy source to targeting new and renewable energy sources (NRES). It is aimed at reducing the country s dependence on fossil fuels and exposure to price fluctuations in international markets, as well as protecting the environment in pursuit of greener economic growth. The thrust of the policy is to create a market-based environment that promotes private sector participation and encourages research and development and technology transfer on NRES. At present, geothermal and hydro resources have already made a dent on power generation. The same cannot be said of renewables. The incentives available to NRES projects, particularly for on-grid power generation, are listed below. Table II.32 Incentives Available for the Development of NRES Incentive 1 Income tax holiday (ITH) For the first seven (7) years of its commercial operations, the duly registered RE (renewable energy) developer shall be exempt from income taxes levied by the national government. 2 Duty-free importation of RE machinery, equipment and materials Importation of RE machinery equipment, and materials shall be duty fee within the first ten (10) years upon the issuance of a certification of an RE developer 3 Special realty tax rates on equipment and machinery Realty and other taxes on civil works, equipment, machinery and other improvements of a registered RE developer actually and exclusively used for RE facilities shall not exceed one and a half percent (1.5%) of their original cost less accumulated normal depreciation or net book value. 4 Net operating loss carry-over (NOLCO) The NOLCO of the RE developer during the first three (3) years from the start of commercial operation shall be carried over as a deduction from gross income for the next seven (7) consecutive taxable years immediately following the year of such loss. 5 Corporate tax rate After seven (7) years of income tax holiday, all RE developers shall pay a corporate tax of ten percent (10%) on its next taxable income. 6 Accelerated depreciation, using either the declining balance method or sum-of-years digit method, if and only if an RE project fails to receive an ITH before full operation 7 Zero percent value-added tax rate on sale of fuel or power generated from renewable sources of energy and zero-rated value-added tax on purchases of local supply of goods, properties and services for the development, construction and installation of the plant facilities of the RE developer 8 Tax exemption of carbon credits All proceeds from the sale of carbon emission credits shall be exempt from any and all taxes. 9 Tax credit on domestic capital equipment and services A tax credit equivalent to 100% of the value of the value-added tax and custom duties that would have been paid on the RE machinery, equipment, materials and parts had these items been imported shall be given to an RE operating contract holder who purchases such from a domestic manufacturer. Moreover, intermittent renewable energy (RE) power is considered must dispatch, thereby reducing the commercial risks for RE developers. The Renewable Energy Act of 2008 also declares the RE sector a priority investment sector to be included in the country s Investment Priority Plan. It entitles registered RE developers to the Board of Investment (BOI) incentives: tax and duty-free importation of component, part and materials; tax credit on domestic capital components, parts and materials; income tax holiday and exemption; and zero-rated value-added tax transactions, which are already covered in the list of incentives in the table above. Final Report Page 49

71 The Renewable Energy Act of 2008 also stipulates the following with respect to the government share from power sales from renewable resources: The government share on existing and new RE development projects shall be equal to one percent (1%) of the gross income of RE resource developers resulting from the sale of renewable energy produced and such other income incidental to and arising from the renewable energy generation, transmission, and sale of electric power except for indigenous geothermal energy, which shall be at one and a half percent (1.5%) of gross income. To accelerate the development of on-grid renewable energy markets, the Renewable Energy Act of 2008 also mandates the setting up of a feed-in tariff system for electricity produced from wind, solar, ocean, run-of-river hydropower and biomass. The application period of the fixed tariffs shall not be less than twelve (12) years. On 27 July 2012, the Energy Regulatory Commission (ERC) approved the initial feed-in tariffs (FITs) for power generated from run-ofriver hydro, biomass, wind and solar energy, as given in the table below. The proposed FITs forwarded by the National Renewable Energy Board (NREB) in its 16 May 2011 petition to the ERC are also given in the following table. The ERC deferred fixing the FIT for ocean thermal energy conversion for further study. Table II.33 FIT Rates for NRES RE Source Approved FIT (PhP/kwh) NREB Proposed FIT (PhP/kwh) Run-of-river hydro Biomass Wind Solar The ERC explained that the reason it approved FITs lower than those proposed by NREB was that it used newer data on construction costs of representative plants and lower rate of return. And yet even if the approved FITs are much lower than proposed, it is worth noting that the average generation cost in 2011 (P4.98 per kwh) 31 is significantly less than any of these approved rates. Thus, the full implementation of FIT may be expected to pull up current level of electricity prices. 31 This is estimated as follow: generation cost for all DUs in Annex II.1 (P994.05) divided by 200 kwh. Final Report Page 50

72 III. Structure of Electricity Markets in Other ASEAN Economies Before benchmarking Philippine electricity prices with the rest of the region, it is useful to lay down the structural similarities and differences among the markets. This section provides a brief glimpse of the other ASEAN markets. A more extensive discussion of these markets is presented in Volume II. In brief, it is shown than competition-based Philippine and Singapore electricity markets share many similar features that stand in sharp contrast to the heavily regulated and traditionally structured markets of Indonesia, Malaysia and Thailand. 1. Indonesia 1.1 Market Structure The electricity market of Indonesia is dominated by the state-owned Perusahaan Listrik Negara (PLN, National Electric Company). Except for several small, closed private networks operating in industrial areas, PLN is virtually the only supplier of electricity in the country. This is because under the 1985 Electricity Law, only public utilities are allowed to supply electric services. Figure III.1 Structure of Indonesian Electricity Market Perusahaan Listrik Negara (PLN) Generation G IPPs Transmission & system operation Self-generation Distribution C U S T O M E R S The generation sector was partially liberalized in the early 1990s, when private investors were allowed to enter the market as independent power producers (IPPs). However, they were required to sell all generated power to PLN. The Purchase Power Agreement (PPA) between PLN and an IPP is usually awarded through competitive bidding, but some IPPs are appointed. There are also small power plants, operated by private power utilities which supply power to limited areas or generate them for their own consumption. By 1997, PLN had 26 long-term PPAs with private investors. The Asian financial crisis dampened the interest of the private sector as PLN defaulted on its obligations to the IPPs. Owing to the drastic drop in the value of Rupiah (Rp), payments to IPPs, under prices stipulated in the PPAs, Final Report Page 51

73 exceeded PLN s revenues from its customers. The private sector interest in the market was revived only in 2005 after the PPAs were renegotiated and the PLN s debt problem was resolved. Total electricity generated in 2011 was 183,421 GWh. Of this, 78% was delivered by PLNowned power plants, 19% by 28 IPPs, and the rest was self-generated. Table III.1 shows the fuel mix of installed capacity and generated power. Table III.1 Installed Capacity (MW) and Energy Produced (GWh) in Indonesia, 2011 Hydro Oil Coal Geothermal Gas Others Total Installed Capacity PLN 3, , ,547.2 Private power , , ,284.1 producers (IPPs + selfgenerated) Total 3, , , , , ,831.3 Energy produced PLN 10, , , , , ,739.7 Private power 2, , , , , ,682.0 producers (IPPs + selfgenerated) Total 12, , , , , ,421.7 Source: Statistik Ketenagalistrikan dan Energi No and PLN Statistics 2011 PLN owns the national transmission and distribution assets. It is the only entity authorized to use these facilities. If a private generator would like to sell to others, it is required to develop and build its own closed off-grid network. It must hold a special license that allows it to generate electricity and sell to a limited number of consumers, which are mostly industrial estates and building management, hospitals, schools and others. Some cooperatives and local government units are also allowed to operate off-grid networks in areas not covered by PLN s services. In September 2002, the Government of Indonesia enacted Law No. 20 on Electricity to replace the old law No. 15/1985. This law was meant to introduce competition in the electricity market within a five-year period. The three main activities, namely generation, transmission and distribution, integrated under the control of PLN were to be unbundled to allow private investors participation in each of these activities. Such a move was expected to raise finances for the construction of new power plants. But in December 2004, Indonesia s constitutional court annulled this law on the grounds that it violated the constitution. The 1985 law was reinstated as a result of this cancellation. In 2009, Indonesia enacted yet another electricity law, No. 30/2009, an improvement over the 1985 law, but carried less reform and liberalization provisions than the law that it superseded. The government retains control over electric power services, although the supply of electricity may be carried out by central or regional governments through PLN, or by regional utilities. IPPs were allowed to engage in retail supply. Private investors may now sell directly to end-users as long as they operated in an area not being served by PLN. Regional governments were empowered to award licenses for private electricity projects and to set up companies to provide electricity services. A more recent issuance, Government Regulation No. 42/2012, stipulates that those owning transmission and distribution assets may lease these facilities to other suppliers. As a result, private generators do not have to build their own transmission or distribution network since Final Report Page 52

74 they may lease these facilities from existing providers such as PLN. It is expected that this will change the structure of the electricity market and end the more than 60-year monopoly of PLN. 1.2 Recent Performance The current national coverage of electricity services is 70%, which is considered low compared to other countries in ASEAN. More areas are covered in the western part of the archipelago, particularly in Java and Bali, where the electrification ratio exceeds 70%. In the eastern part, which includes Papua and Nusa Tenggara islands (NTB and NTT), less than 40% of the population is covered. This situation has adversely affected Indonesia s economic development. Besides the low coverage ratio, the industry is also beset by insufficient capacity and poor power loading management. In the last decade, annual growth in demand for electricity was more than 6% but supply expanded only by 5%. Since 2002, gross production of power has fallen short of demand, and the gap is widening. This reflects insufficient capacity to cope with demand that has been projected to increase by 9% annually. In 2010, the required capacity was 39,770 MW against existing capacity of only 34,000 MW. Realizing the critical situation of power services, the government launched in 2008 several programs to develop new power plants. These programs were expected to provide additional 10,000 MW of power by 2011 and another 10,000 MW by 2014, which should be sufficient to meet the demand in Financing problems, however, delayed the completion of the first phase of this program for at least a year. Indonesia continues to rely heavily on oil-based energy sources which account for 67% of installed capacity. However, this is likely to change when the new capacity comes on stream. The additional 10,000 MW capacity is expected to be delivered by 35 new coalbased plants, while the other 10,000 MW, by plants running on natural gas, hydro and geothermal. By 2020, the share of oil-based plants in installed capacity is expected to be reduced to less than 30%. Another problem besetting the electricity market of Indonesia is that many areas are isolated because of transmission and distribution network problems. Only the Java-Bali grid systems are fully interconnected. Frequent blackouts in many regions are often not a result of insufficient capacity but lack of transmission and distribution facilities. Transmission losses are high and electricity theft is rampant. 2. Malaysia 2.1 Market Structure The Malaysian electricity supply industry has three separate grid systems, servicing Peninsular Malaysia, Sabah and Sarawak. These systems are operated and managed separately by state-owned utilities Tenaga Nasional Berhad (TNB), Sabah Electricity SDN Berhad (SESB) and Syarikat Sesco Berhad (SESCO), respectively. In 2010, Peninsular Malaysia accounted for 96 percent of total electricity consumption in the country. Given its size in relation to the overall market and the fact that most of the available information pertain to the mainland, this report refers to the grid system in Peninsular Malaysia as the Malaysian market. Until 1992, the electricity supply industry in Malaysia was completely vertically integrated, i.e., TNB owned all generation, transmission and distribution facilities. A power crisis in the 1990s compelled TNB to enter into 21-year power purchase agreements (PPAs) with Final Report Page 53

75 independent power producers (IPPs). 32 At present, the market is characterized by a single buyer model where TNB is the sole buyer of power generated by the IPPs and the only entity engaged in transmission and distribution of electricity. The figure below depicts the current market structure. Figure III.2 Structure of Malaysian Electricity Supply Industry Source: Figure 3.1 in Hassan et al. (2009) The energy sector, which includes oil and gas, and the electricity industry, is regulated by Suruhanjaya Tenaga (Energy Commission), a statutory body created by the Energy Commission Act of There were plans to restructure the electricity market since the early 1990s but the major initiatives, such as the establishment of an independent grid system operator, appointment of independent market operator, and introduction of wholesale market competition, were put on hold. 2.2 Sector Performance The total generation capacity of Malaysia in 2010 stood at 27,179 MW. Of this, TNB owns 7 thermal and 8 hydro plants, representing 26 percent of total capacity. Bulk of the capacity is owned by private utilities or IPPs. Despite recent policies promoting the use of renewable energy, the share of Small Renewable Energy Producers (SREP) is still marginal. Table III.2 Installed Capacity in Malaysia by Major Power Producers, 2010 (in percent) Share Tenaga Nasional Berhad IPP (Peninsular Malaysia) IPP (Sarawak) 3.01 IPP (Sabah) 2.21 Co-Generation (Peninsular Malaysia) 3.37 Co-Generation (Sabah) 0.64 Self-generation 5.09 SREP (Peninsular Malaysia) 0.10 SREP (Sabah) 0.14 SESB Hassan, M. Y. B., F. Hussin, and M. F. Othman (2009), A Study of the Electricity Market Models in the Restructured Electricity Industry, available at Final Report Page 54

76 Share SESCO 1.95 Total Source: Energy Commission. As of 2010, gas-based power plants accounted for 56% and 52% of installed capacity and generated power, respectively (Table III.3). To reduce dependence on natural gas, Malaysia has turned to coal. The share of coal in the generation mix has increased from 8.8 percent in 2000 to 39.5 percent in 2010, while natural gas declined from 77 percent to 52 percent during the same period. Table III.3 Electricity Fuel Mix in Malaysia Installed Capacity Generated Power Total as of ,179 MW 125,045 GWh Share of: (in percent) Natural gas Coal Hydro Diesel Oil Biomass Others Source: Energy Commission. Despite recognizing the need to diversify the fuel mix, the government continues to provide subsidy to consumption of natural gas. The national oil corporation, PETRONAS, supplies natural gas to TNB and IPPs at about one-fourth of its market price. In 2010, the average gas price sold by PETRONAS to the electricity industry was RM10.7 per MMBTu; the unsubsidized price was RM41.2 per MMBTu. This issue might be exacerbated by the fact that PETRONAS has to import about a third of the gas that it supplies to the electricity market. Recently, the continued subsidy to consumption of natural gas is at the center of policy debate due to increasing national debt and fiscal deficit. Of the RM74 billion total subsidy in 2009, nearly one-third (RM23.5 billion) was allocated to fuel and energy. It is also recognized that Malaysia has only 33 years of natural gas reserves and 19 years of oil reserves, while the demand for energy is increasing. Malaysia s energy sources for electricity are based on a four-fuel mix strategy: gas, oil, hydro, and coal. From 1970 to 1980s, oil was relied heavily for generation, but this overreliance led to rapid depletion of oil reserves. Since the mid-1980s, other fossil fuels especially gas and coal, are increasingly relied upon for generation. By 2010, it is estimated that gas and coal contributed 92% in generation; hydro and oil account for the remainder (7 and 1%, respectively). The Malaysian government is seeking to intensify the development of renewable energy, particularly biomass, as the 'fifth fuel' resource under the country s Fuel Diversification Policy. The policy, set out in 2001, aims to raise the share of renewable energy to 5% by 2005, (equal to between 500 and 600 MW of installed capacity). The policy involves provision of fiscal incentives, such as investment tax allowances, and the Small Renewable Energy Program (SREP), which promotes the connection of small renewable power generation plants to the national grid. Final Report Page 55

77 The Small Renewable Energy Program allows renewable projects with up to 10 MW of capacity to sell their output to TNB, under a 21-year license agreement. Numerous applications for the program have been received, mainly involving biomass, and of these over half are for palm oil waste. In 2005, there were 28 approved biomass projects involving the installation of 194 MW of grid-connected capacity. There were also four approved landfill gas-based projects, with 9 MW of capacity, and 18 mini hydro-electric projects offering 69.9 MW of total capacity. But the most promising potential for renewable energy in Malaysia is in biomass and biogas from palm oil, considering that 15% of the total land area is covered by this crop. 3. Thailand 3.1 Market Structure The electricity market of Thailand is not very different from the vertically integrated markets of Indonesia and Malaysia. Most of the generation and all transmission activities are operated by a state-owned utility, Electricity Generating Authority of Thailand (EGAT). However, the distribution and supply activities are the responsibility of the Metropolitan Electricity Authority (MEA) and Provincial Electricity Authority (PEA). EGAT generates and transmits electricity to MEA and PEA. MEA s service area includes Bangkok, Nonthaburi and Samut Prakan Provinces, covering an area of 3,192 square kilometers. PEA, on the other hand, distributes electricity to customers outside of the MEA s jurisdiction. The service area of PEA is approximately 510,000 square kilometers, accounting for 99 percent of the total area of the country. Clearly, PEA is a bigger organization and serves a much wider area and a larger number of customers than MEA. PEA s service area is 160 times bigger than MEA s. But demand per square kilometer in areas covered by MEA is higher. Since 1992, the government has been encouraging the private sector to participate in the generation business either as Very Small Power Producers (VSPPs), Small Power Producers (SPPs) or Independent Power Producers (IPPs). The SPP and VSPP programs focus on electricity production from biogas, biomass, municipal solid waste (MSW), wind, solar, and other renewable energy sources. SPPs are small power projects that are either co-generators or facilities that use renewable energy, such as waste/residues from agricultural activities or garbage. They sell no more than 90 MW of power to EGAT for each project, under a firm or non-firm contract 33. Since SPPs can sell power directly to consumers located in their vicinity, their generation capacity is usually between 120 and150 MW. IPPs have usually larger generating capacity than SPPs since they can use commercial energy such as natural gas, indigenous and imported coal and emulsion. Under the IPP program, investors can sell electricity to EGAT under a long-term arrangement through a competitive bidding process. The sale of electricity to EGAT by either an SPP or IPP is covered by a power purchase agreement (PPA). The first government attempt to encourage the participation of the private sector in power generation was the establishment of EGAT s subsidiary companies whose stocks were to be publicly listed. Two subsidiary companies were formed: the Electricity Generating Company (EGCO) in 1992 and the Ratchaburi Electricity Generating Holding Public Company Limited (RATCH) in EGCO became the first IPP in Thailand. EGCO was established to acquire EGAT s Rayong power plant which has a capacity of 1,232 MW. In 1995, EGCO 33 A firm contract is one that is drawn for at least five years and under which the capacity is specified and the capacity and energy payments are made. A contract is non-firm if it covers less than five years and under which only the energy payment is made. Final Report Page 56

78 also acquired from EGAT the Khanom power plant with capacity of 824 MW. RATCH, on the other hand, acquired EGAT s Ratchaburi power plant complex, which has a production capacity of 3,645 MW and is expandable to 5,200 MW. EGCO and RATCH were initially 100 percent owned by EGAT. After public offering to both international and domestic investors, EGAT s holding in EGCO and RATCH was reduced to 25 and 45 percent, respectively. 34 Both companies now operate power plants and sell electricity to EGAT under long-term PPAs. 35 In Figure III.3, the electricity supplied by the two subsidiaries to EGAT accounted for 26 percent of the gross energy generated and purchased in Thailand; the other IPPs supply only 10 percent. EGCO and RATCH are considered the largest electricity private generators. Figure III.3 Structure of the Electricity Market in Thailand Source: Jarvis (2009) As of 2009, EGAT has signed 7 PPAs with IPPs, 90 PPAs with SPPs, 274 VSPPs with PEA and 51 VSPPs with MEA. IPPs and SPPs account for 42 and 7 percent of installed generation capacity, respectively, whereas EGAT s share is 49 per cent. EGAT also 34 As of 31 March 2001, the shareholding structure of the EGCO comprises per cent from EGAT, per cent from CLP Power Projects (Thailand) Limited and per cent from the general public. For the RATCH, the shareholding structure is roughly the following: 45 per cent of shares retained by EGAT, 40 per cent distributed to the general public and 15 per cent by EGAT employees and EGAT provident fund. 35 All electricity produced by Rayong Electricity Generating Co. Ltd. is sold to EGAT, under a 20-year PPA whereas output from Khanom Electricity Generating Co. Ltd. is sold directly to EGAT under two PPAs, which are one 20-year PPA for the combined-cycle unit and the first thermal plant and one 15- year PPA for the second thermal plant. Ratchaburi Electricity Generating Co. Ltd. sells electricity to EGAT by a 25-year PPA. Final Report Page 57

79 purchases electricity from the neighboring countries such as Lao People s Democratic Republic and Malaysia. As shown in Figure III.3, under the current structure, EGAT acts as a monopsonist in the generation business, and a natural monopolist in the transmission business. MEA and PEA are the sole electricity distributors and retailers in their respective areas. The current set-up is referred to as the Enhanced Single Buyer Model which was approved by government in This model is considered an improvement over the old structure because EGAT is forced financially to unbundle its generation and transmission activities. The salient features are summarized below. Table III.4 Comparison between Single and Enhanced Single Buyer Models Characteristics Single Buyer Model Enhanced Single Buyer Model Market model Single buyer Single buyer Asset ownership No asset ownership unbundling of EGAT s generation and transmission Account unbundling of EGAT s generation and transmission New capacity allocation Competitive bidding; EPPO/NEPC specifies eligible bidders New Capacity allocated through process determined by regulator System operator Embedded within transmission Ring fenced within transmission End user choice No choice Retain promotion of SPP and create new opportunities for captive power Tariff Regulated based on CPI-X Regulated based on CPI-X and other efficiency drivers Third party access No third party access SPP and captive power Regulator involvement Source: Boston Consulting Group 3.2 Regulatory Regime No formal regulator-eppo and NEPC perform policy setting and key regulatory functions Strong regulator under Ministry of Energy (Ministerial agency); policy setting by Ministry of Energy Before 2007, there was no formal and independent regulatory body for the electricity sector. Policies and regulations, including price setting, were made by the National Energy Policy Council (NEPC), established under the National Energy Policy Council Act, B.E (1992). The Energy Policy and Planning Office (EPPO) acted as the Secretariat. NEPC used CPI-X to regulate retail electricity tariff, where CPI is Consumer Price Index and X is an efficiency improvement factor. The Ministry of Energy 36 (MOE) was set up in 2002 to unify more than 20 government agencies in nine ministries and SOEs directly related to the energy planning policy, regulation and implementation. The MOE has the authority to oversee the procurement, development and management of energy in Thailand. EPPO became part of MOE and is responsible for strategic energy planning. The MOE also assumed authority over energyrelated SOEs, namely: EGAT (formerly under the Office of the Prime Minister); the PTT Public Company Limited (formerly under the Ministry of Industry) and Bangchak Petroleum Public Company Limited (formerly under the Ministry of Finance). But MEA and PEA remain under the Ministry of Interior. In December 2007, the National Legislative Assembly passed the Energy Industry Act (EIA), which consolidated the laws relating to electricity and natural gas transmission networks. The main objectives of the Act are to promote competition and private sector participation, 36 On 3 October 2002 the Thaksin government decided to restructure the Cabinet and established the new ministries, one of which is the Ministry of Energy. Final Report Page 58

80 and establish independent, transparent, and accountable energy regulator, and provide a new regulatory framework. The key rationale for EIA is to have clear assignment of roles among government agencies involved in the energy industry. The law does not prescribe a specific market model for electricity and natural gas. The industry restructuring is left to the regulatory agencies that were created by the Act. The Act created the Energy Regulatory Commission (ERC) and stipulated the functions of MOE among others, to recommend energy policies to the Cabinet, and consider the power development plan, and investment and operational plans formulated by ERC. According to the Act, policymaking for the energy industry is to be exercised by a number of government agencies including the Cabinet, MOE and NEPC. However, the Act centralized all regulatory functions to ERC. Figure III.4 Policymaking Bodies in the Electricity Sector in Thailand The ERC is responsible for regulating the Thai energy industry, defined as the electricity industry, natural gas industry or energy network system business. It therefore covers generation, transmission, distribution and supply, as well as gas transmission and storage, transformation of natural gas from liquid to gas, and wholesale or retail sale of natural gas via a natural gas distribution system. 3.3 Progress and Challenges in Regulation As a newly established organization, ERC is still building up its institutional capacity. Nonetheless ERC has been performing regulatory functions which include determination of Ft (automatic adjustment mechanism) on electricity tariffs; setting of gas pipeline tariffs; issuance of licenses to state-owned enterprises and private energy operators; and appointment of Regional Energy Consumer Committees nationwide. ERC s work has been slowed down by the inadequate capacity of its staff members. This is because ERC is limited to hiring staff members from other government energy agencies, notably the Ministry of Energy. As a result, it has to contend with the bureaucratic rigidities in hiring and transferring employees from other government agencies. Moreover, staff members tend to bring to their jobs a mindset shaped by a career within the bureaucratic system, which is probably not suitable under a new regulatory framework. (Koomsup and Sirasoontorn, 2011). Final Report Page 59

81 ERC relies on international and domestic consultants to fill up the capacity deficiencies of its staff, particularly on electricity tariff determination and gas pipeline tariff review. As a long term measure, ERC is building the capacity of its staff members through training and short courses in the USA and UK. Since ERC was established, there has been no substantial progress on plans to introduce greater competition in the electricity market. But ERC is indirectly promoting competition by issuing licenses to new suppliers, setting rules and procedures for granting new licenses, and introducing third party access in gas transmission network, although this has yet to be implemented. ERC s authority has been undermined also by the national government which has been implementing populist policies, including offering free electricity to poor electricity users whose usage is less than 50 kwh (initially 90 kwh) a month. The national government has also issued orders directly contravening ERC s exclusive powers to set tariffs. Even ERC s authority to issue licenses has been weakened. The NEPC delegated the authority of selecting SPPs and VSPPs to the Ministry of Energy, thereby relegating the role of ERC to mere issuer of licenses. And yet one of the objectives in establishing ERC is to centralize and streamline the licensing functions. In practice, power producers have to ask permission to set up power plants from various government agencies, namely the Department of Industrial Works in the Ministry of Industry; the Department of Public Works and Town & Country Planning in the Ministry of Interior; and local government authorities. This makes it costly for small and very small producers to set up their power plants. (Koomsup and Sirasoontorn, 2011). ERC is also experiencing difficulties in forcing operators to disclose pertinent information for tariff setting. The Commission has been criticized for its lack of autonomy and independence from political interference, particularly in tariff setting. 4. Singapore 4.1 Current Market Structure The National Electricity Market of Singapore (NEMS) is almost fully liberalized and horizontally unbundled by generation, transmission and distribution (T&D) and wholesale and retails. The players in the NEMS can be classified into seven main types: industry regulator, market operator, grid operator/owner, market support services licensee (MSSL), generators, retailers, and consumers. The Energy Market Authority (EMA) is the industry regulator, Energy Market Company (EMC) is the market operator, SP PowerGrid is the grid operator and owner and SP Services is the MSSL. Figure III.5 presents a schematic diagram of the electricity industry structure in Singapore. Final Report Page 60

82 Figure III.5 Structure of Electricity Industry in Singapore Source: Energy Market Authority, Singapore The Energy Market Company (EMC), a joint venture between EMA and Marketplace Company of New Zealand, was established to implement and operate the wholesale electricity market. NEMS can be split into two sectors contestable and non-contestable. The players in the contestable sector are generation licensees, electricity retail licensees, wholesale (generation) licensees and wholesale (interruptible load service) licensees. The players in the non-contestable sector are a market company, a transmission licensee, a transmission agent licensee and a market support services licensee. Companies in the non-contestable sector are considered natural monopolies. There are currently 12 generation companies, of which YTL PowerSeraya, Tuas Power Generation and Senoko Energy make up more than 80% of total installed capacity. The name-plate rating of each generating unit should be at least 10MW. There are seven retailers catering to the contestable consumers. They are market participant retailers who should register with the Energy Market Company (EMC) to purchase electricity from the NEMS. The retailers are Keppel Electric, Sembcorp Power, Tuas Power Supply, Senoko Energy Supply, Seraya Energy, GMR Supply (formerly known as Island Power Supply) and Diamond Energy Supply. In addition, there are two different classes of wholesalers: interruptible load service 37 providers and generation providers 38. The capacity and market shares of these wholesalers are a very small part of the overall NEMS. The total capacity of generation providers is MW. 37 A wholesaler (interruptible load) licensee is issued to companies who can offer their own load to be interrupted or provide services to other consumers interested in offering their load to be interrupted. Interruptible Load Service Providers are Diamond Energy, Air Products Singapore, and Chesterfield Manufacturing. 38 A wholesaler (generation) licensee is issued to a firm that generates electricity by means of one or more generating units with individual name-plate rating of 1MW or more but less than 10MW and their generating unit(s) is connected to the power grid. Generation Providers are Biofuels Industries, Pfizer Asia Pacific, Banyan Utilities, ISK Singapore, Singapore Oxygen Air Liquide, MSD International, Green Power Asia, CGNPC Solar-Biofuel Power (Singapore), Eco Special Waste Management and Singapore LNG Crporation. (A firm whose aggregate generating capacity exceeds 10MW has to bid to secure dispatch.) Final Report Page 61

83 Consumers belong to either contestable or non-contestable pool by virtue of their electricity consumption. Consumers with average monthly consumption above 10,000 kwh are in the contestable pool, while those with smaller consumption volume (including residential users) are in the non-contestable pool. Contestable consumers can purchase electricity from an electricity retailer, indirectly from NEMS through the MSSL or directly from the NEMS provided they are allowed and registered to trade in the NEMS. Non-contestable consumers are served by the MSSL, SP Services. Most industrial consumers purchase electricity from the wholesale electricity market and pay electricity by time and amount of electricity use. The remaining consumers, representing about 25% of total electricity demand in Singapore or 1 million customers, are serviced by the MSSL and their electricity consumption is charged based on a tariff schedule that is adjusted every three months to reflect changes in the global fuel market. 4.2 Comparison of Philippine and Singapore Wholesale Electricity Market During the 1990s the electricity industry around the world underwent a transformation whose underlying purpose was to introduce competition in the industry. The transformation involved the separation of generation, transmission, distribution, and retail of electricity. Competition was introduced in generation and retail while transmission and distribution remained as regulated monopolies. Within this general framework, different countries followed different approaches to restructuring involving such issues as privatization of generation and transmission assets, organizational structure and governance of the wholesale and retail markets, and regulation of the restructured industry. Singapore and the Philippines were among the countries that joined this worldwide phenomenon. In Singapore, initial steps toward restructuring started in 1995 when the electricity functions of the Public Utility Board were turned over to Singapore Power (SP), a government-owned entity. In 1998, the Singapore Electricity Pool (SEP) was set up as a day-ahead market where the market participants were the Singapore Power which operated the generation companies, the SP PowerGrid which owned the grid and was the system operator, and the SP Services which was the sole purchaser in the electricity pool and was the retail arm of SP. Both SP PowerGrid and SP Services were subsidiaries of SP. In 2001, a new configuration was introduced into the electricity industry with the enactment of the Electricity Act and the Energy Market Authority of Singapore Act. The Electricity Act established the National Electricity Market of Singapore (NEMS) and the Energy Market Authority (EMA) established the Energy Market Company (EMC) to operate and administer the wholesale electricity spot market. Two of the three largest generation companies were divested, competition in generation was introduced, and liberalization of the retail market started. Then on January 1, 2003, the NEMS commenced operations. In the Philippines, laws were passed in the early 1990s to encourage private sector participation in power generation and in 1996, an Omnibus Power Industry bill seeking to restructure the electric power industry was filed in the Philippine Congress. But it took five years before the Electric Power Industry Reform Act (EPIRA) of 2001 was enacted. EPIRA laid out the basis for the full restructuring and privatization of the power industry. It created the Wholesale Electricity Spot Market (WESM) and the Philippine Electricity Market Corporation (PEMC) to operate and administer the wholesale electricity spot market. WESM commenced commercial operations on June 26, The markets that resulted from the restructuring and market reforms of the electricity industry in these two countries have many similarities. The differences are in the details and speed of implementation. For example, the wholesale spot markets in both countries are mandatory pools with uniform price auctions that employ merit orders to determine nodal Final Report Page 62

84 prices. In both markets, the dispatched generators are paid the prices at the nodes where they injected electricity. But while buyers in the Philippine market pay the nodal prices, buyers in the Singapore market pay the same price called the Uniform Singapore Electricity Price, being the weighted average of all the nodal prices. As another example, both markets call for a gradual introduction of retail competition. But while the Singapore market immediately introduced retail competition, the Philippine market has yet to implement it ten years after the enactment of EPIRA. Both the Philippine and Singapore wholesale electricity markets allow sellers and buyers to enter into financial bilateral contracts as hedges against the volatility of the spot price outcomes but the physical flows of power are all within the pool. The parties to the contract may use wholesale market settlement system or they may opt to settle outside the system. In the Philippine wholesale electricity spot market (WESM), all the bilateral contracts are freely negotiated between the contracting parties although ERC can exercise oversight function. The bilateral contracts quantity (BCQ) was 56% of the total electricity traded at the start of WESM operations in June The BCQ has grown to as high as 95% in April 2011 and averaged 92% in the first 10 months of Breaching the 90% mark is explained by the fact that five years after the establishment of WESM, the distributors were free of the legal requirement to source no more than 90% of their energy purchases through bilateral contracts 39. The effect of bilateral contracts on wholesale electricity prices in the Philippines have not been studied fully. But in the case of MERALCO, as reported in Section II.6.1, the bilateral contracts dampened the volatility of spot prices. The Singapore market has, in addition to the regular bilateral contracts, a special contract called the vesting contract introduced in The explicit objective of vesting contracts, as enunciated by the EMA, 40 is to curb market power in order to promote efficiency and competition in the electricity market for the benefit of the consumers. 41 Under the vesting contracts, generators are committed to sell a specified quantity of electricity (the vesting contract quantity) at a specified price (the vesting contract price). This reduces the incentive of generators to exercise market power by withholding capacity. 42 Because the Singapore wholesale electricity market is concentrated (more than 80% of installed capacity belongs to the three largest generation companies), vesting contracts are imposed by the EMA on these three companies. SP Services, which is also the Market Support Services Licensee, is the counterparty, on behalf of the consumers, to every vesting contract. The vesting quantity (VQ) started in 2004 at 65% of total electricity demand and stands at 55% in The long-term plan is to reduce VQ as market power is diminished with the entry of new generating capacity. The vesting price is set based on the Long Run Marginal Cost (LRMC) of the most efficient generation technology -currently, this technology is Combined Cycle Gas Turbine (CCGT) - that account for more than 25% of total electricity demand. Both vesting quantity and vesting price are reviewed and reset by the EMA every two years. In calculating the components of the vesting contracts during this review, the EMA takes into account the comments of the vesting contract holders as well as advice from experts. 39 Sec. 45(c), EPIRA. 40 Vesting Contracts, Energy Market Authority Website, 13 November Although curbing market power is the declared objective of vesting contracts, we point out that, just like other bilateral contracts, vesting contracts also provide contracting parties with financial hedges. 42 In the Philippine wholesale electricity spot market, a must-offer rule is required of generators to prevent capacity withholding, i.e., the generator must offer all its available capacity. However, this is not easy to enforce because there are many reasons for not offering all available capacity and they are not easy to verify. Final Report Page 63

85 One study has shown that just a year after the introduction of vesting contracts, the impact on the Singapore electricity market was palpable. Chang (2005) compared data in 2003 and 2004 and concluded that the market was more competitive in 2004, the year vesting contract was required. 43 The following table compares the features of the two markets in terms of market structure, rules, and price determination. Some relevant industry statistics are also provided at the end of the table. 43 Youngho Chang, Pricing Behavior, Market Power, and Vesting Contracts in a Deregulated Electricity Market, Department of Economics, National University of Singapore, December Final Report Page 64

86 Table III.5 Comparison of Philippine and Singapore Wholesale Electricity Market Philippines Singapore Electricity Reform Legislation Electric Power Industry Reform Act (EPIRA) of 2001 Electricity Act of 2001 Energy Market Authority of Singapore Act of 2001 Regulatory Authority Energy Regulatory Commission (ERC): ERC is an independent quasi-regulatory body whose functions include promoting competition, encouraging market development, ensuring customer choice, and penalizing abuse of market power. It enforces the rules governing the operations of the Wholesale Electricity Spot Market (WESM), the activities of the Market Operator and the market participants for the purpose of ensuring greater supply and rational pricing of electricity. Department of Energy (DOE): The DOE established the WESM and formulated its rules. It exercises some administrative supervision of WESM as the Chairman of the governing Board of WESM is the DOE Secretary. (WESM Market Report, Jul 2010-Jun 2011) Energy Market Authority (EMA): EMA is responsible for the regulation of the electricity sector. It (a) issues licenses to authorize entities to conduct electricity-related functions, (b) made the initial wholesale market rules, (c) governs the conduct of the Energy Market Company (EMC), the Power System Operator (PSO), the market participants, and the market support services licencee (MSSL). (Energy Market Authority, Introduction to the National Electricity Market of Singapore, 11 Oct 2010) Privatization of Generation Companies The Wholesale Electricity Market The government is still in the process of privatizing its generating plants. As of April 2011, 27% of the installed generating capacity remains in government hands. (Table 13, 18 th Status Report on EPIRA Implementation, DOE) The wholesale spot market. The spot market is a real-time bid-based market for the hourly trading of energy. The Wholesale Electricity Spot Market (WESM) 44 is organized as a mandatory pool (also called a gross pool) which means that all generators are required to sell all their electricity outputs in the pool, including those covered by bilateral contracts, and all buyers of electricity buy from the pool. All generating companies with facilities connected to the transmission or distribution systems and all customers purchasing electricity supplied through the transmission system have to register as pool members. The government completed divesting itself of all generating companies in December (NEMS Market Report 2009) The wholesale spot market. The spot market is a real-time market for the half-hourly trading of energy, reserves, and regulation under the principle of co-optimization. The Energy Market Company (EMC) is the company licensed by EMA to operate and administer Singapore s wholesale electricity market called the National Electricity Market of Singapore (NEMS). All of Singapore s electricity is bought and sold through the EMC in the NEMS. Generation companies offer every half-hour to sell electricity into the wholesale market. All sales and purchases of electricity through the wholesale market are settled through EMC. (EMA Website, July 25, 2012) 44 The Philippines has three Grids: Luzon, Visayas, and Mindanao Grids. WESM operates only in the Luzon and Visayas Grids. Inclusion of the Mindanao Grid is under study. Final Report Page 65

87 The Market Operator The System Operator Trading Participants Philippines Ancillary Services. All ancillary services are contracted by the System Operator. (Regulatory approval for including reserves (regulating, contingency, dispatchable, interruptible load) in the spot market is still pending. When reserves are traded in the spot market, the principle of co-optimization will be applied.) Bilateral Trading. Buyers and sellers are allowed to enter into financial bilateral contracts as hedges against the volatility of the spot price outcomes but the physical flows of power are all within the pool. The parties to the contract may use WESM s settlement system or they may opt to settle outside WESM. Vesting contracts, defined as bilateral contracts imposed on generators requiring them to sell a specified amount of electricity at a specified price, are not an option in the Philippine wholesale electricity market. The Philippine Electricity Market Corporation (PEMC) acts as the Market Operator (MO) prior to the selection of an Independent Market Operator (IMO). The National Grid Corporation of the Philippines (NGCP), a private corporation, is the System Operator (SO) which also operates and maintains the transmission system. The SO implements the dispatch schedule prepared by the MO. The NGCP is also the wholesale metering service provider. The trading participants include the sellers (generating companies) and the buyers (distribution utilities, bulk consumers, wholesale aggregators). All generating companies with facilities connected to the transmission or distribution systems and all customers purchasing electricity supplied through the transmission system have to register as pool members. Singapore Other ancillary services. Ancillary services other than regulation and reserve, called the procurement market, are contracted by the Energy Market Company in behalf of the Power System Operator (PSO). Bilateral trading. Trading participants can enter into bilateral contracts which are purely financial arrangements whereby participants buy and sell on the spot market and settle between themselves any financial difference implied by their contracts. The parties may choose to use the EMC s settlement system to settle the financial difference under their contracts. Vesting contracts. These are a form of bilateral contracts imposed on the generators by the EMA on the three large generators designed to reduce their market power. SP Services, the Market Support Services Licensee (MSSL), is the counterparty to all vesting contracts. EMA, Introduction to the NEMS, Oct 11, 2010) The Energy Market Company (EMC) operates and administers the wholesale electricity market as an Independent Market Operator. The Power System Operator (PSO), a division of EMA, directs the operation of the high-voltage transmission system. The PSO controls the dispatch of facilities in the wholesale market. The trading participants include the generators, retailers, wholesale traders, contestable consumers, and the Market Support Services Licencee (MSSL). It is generally mandatory for generators with capacity of 10 MW or more to be trading participants. Final Report Page 66

88 Demand Side Bidding Supply Side Bidding Price Determination Scheduling, Dispatch, and Settlement Retail Competition Philippines Although demand side bidding is allowed in the WESM rules, there has been no demand side bidding in practice. The Market Operator forecasts the total demand for each trading interval. Generators compete to supply electricity by submitting pricequantity offers. They are subject to the must offer rule, i.e., every generator must offer its available capacity. Price cap: Price offers cannot exceed PhP62,000/MWh. Based on the price-quantity offers, the MO uses the Market Dispatch Optimization Model (MDOM) to determine the least-cost dispatch quantities that meet the forecasted load while taking into account the security requirements and the system conditions. This results in a dispatch schedule of generators along with the prices at each location (node). A generator is paid the price at the node where it injects electricity. Buyers located in the same customer pricing zone (a group of nodes) pay the same price for electricity, computed as a weighted average of the nodal prices at all off-take nodes within the pricing zone. (WESM Rule 3.2.3). Generators are dispatched by the SO in accordance with real-time dispatch schedule produced by the PEMC. PEMC acts as an agent for all trading participants in WESM to settle all market transactions and additional charges and payments. Retail competition and open access (RCOA) to distribution wires has not been implemented due mainly to the delay in Singapore The market is an offer-only market, i.e., there is no demand side bidding. The PSO provides a forecast of the expected demand for each trading interval. Generators offer capacity by specifying price/quantity pairs into the market. Generators are allowed to offer quantities of 0 MW even if their units have positive available capacities. (Teo, N., Update on the NEMS, Asian Apex, 7 Mar 2011) Price cap: Price offers cannot exceed S$300/MWh. (2009 Market Report, NEMS) Based on the price-quantity offers made by the generators and the load forecast prepared by the EMC, the least-cost dispatch quantities and the market prices are determined each halfhour by a computer model called the Market Clearing Engine (MCE). The MCE takes account of the full range of system constraints and generates energy prices referred to as nodal prices that vary at different points of the network. The differences in nodal energy prices reflect the transmission losses and physical restrictions on the transmission system. Each dispatched generator is paid the market price at the node to which it has been assigned. Buyers in the wholesale energy market pay the Uniform Singapore Energy Price (USEP), a weighted average of the nodal prices at all of the off-take nodes in each half-hour. (Energy Market Authority, Introduction to the NEMS, 11 Oct 2010) Generators are dispatched by the PSO in accordance with real-time dispatch schedule produced by the EMC. The EMC settles all transactions in the spot market. The settlement process uses information from the dispatch, the ex ante prices, and the metered outcomes of each dispatch period. It uses this information to calculate the payments to be made to and by generators and loads participating in the wholesale market. (EMA, Introduction to the NEMS, Oct 2010). Retail market competition was introduced in stages. Since July 2001 consumers with maximum power requirement of 2 MW Final Report Page 67

89 Wholesale Market Governance Some Statistics on the Electricity Markets Capacity Philippines complying with five pre-conditions set by EPIRA. On June 6, 2011, ERC declared that those conditions had been complied with (19 th EPIRA Status Report). It was reported on January 19, 2012 that a kick-off date for RCOA implementation was set for September 26, 2012 (Manila Bulletin, January 19, 2012). As mandated by EPIRA, RCOA implementation will be gradual starting with end-customers with a monthly average peak demand of at least 1 MW for the preceding 12 months as contestable. Two years later, the threshold level for contestability will be reduced to 750 kw. Every year thereafter, ERC will gradually reduce the threshold level until it reaches the household demand level. (EPIRA, Sec. 31). WESM is governed by the Philippine Electricity Market (PEM) Board. The PEM Board is supported by several committees, namely, (a) the Rules Change Committee, (b) the Market Surveillance Committee, (c) the Technical Committee, (d) the PEM Auditor, and (e) the Dispute Resolutions Group and the Dispute Resolution Administrator. (WESM Market Report, Jul 2010 Jun 2011). Installed Capacity, Luzon Grid (Dec 2010): 11,167 MW Note: Up to Dec 25, 2010 WESM operated only in the Luzon Grid. Total Philippine installed capacity in 2010 was 14,976 MW. (18 th Status Report on EPIRA Implementation, DOE) Fuel Mix for Generation Fuel Mix for Luzon Grid, Dec 2010: Coal 33% Natural Gas 24% Hydro 20% Diesel/Oil 15% Geothermal 8% (WESM Market Report 2010/2011) Electricity Generation 2010: Luzon 46,228 GWh Singapore and above have been contestable, i.e., they have been given the option to buy electricity from a retailer, indirectly from the wholesale market through a MSSL or directly from the wholesale market. In June 2003, consumers with average monthly consumption of 20,000 kwh and above became contestable. In December 2003, consumers with average monthly consumption of 10,000 kwh and above became contestable. Noncontestable consumers are supplied by the MSSL. (EMA, Introduction to the NEMS, 11 Oct 2010) As of July 2012, liberalization has opened up 75% of total electricity sales in Singapore to competition. About 13,000 consumers are able to exercise their choice of power. (EMA Website, July 2012) A board of directors referred to as the EMC Board oversees the EMC. In certain cases, the market rules require that the EMC Board itself take action. In other cases, the market rules allocate responsibility to persons or panels appointed by the EMC. These are the following: (a) Dispute Resolution Counsellor, (b) Market Surveillance and Compliance Panel, and (c) Rules Change Panel. (EMA, Introduction to the NEMS, Oct 2010). Licensed Capacity (2010): 9892 MW (EMA Annual Report 2010/2011) Fuel Mix for 2010: Natural Gas 77% Fuel Oil 17% Others 6% (EMA Annual Report 2010/2011) 2010: Singapore 45,368 GWh Final Report Page 68

90 Philippines Philippines 67,743 GWh (WESM Market Report 2010/2011) Demand 2010: Average Demand, Luzon 5,693 MW Peak Demand, Luzon 7,656 MW (18 th Status Report on EPIRA Implementation, DOE) Singapore (EMA Annual Report 2010/2011) 2010: Average Demand 5,008 MW* Peak Demand 6,294 MW** (*EMA Annual Report 2010/2011) (**NEMS Monthly Trading Report, Dec 2010) Final Report Page 69

91 IV. Electricity Prices in Other ASEAN Countries This section reproduces the tariffs in the other selected ASEAN markets based on the four model cases. The regulatory regimes determining these prices are described. This should provide context in the subsequent section where Philippine tariffs are benchmarked against these prices. 1. Indonesia 1.1 Price Structure and Regulation Indonesia has adopted a uniform tariff schedule, i.e., the same set of prices is applied in all parts of Indonesia except in Batam. The retail prices of PLN are set by the government through a Presidential Decree. A number of regulations stipulate the rules in setting prices but there is no provision for regular price adjustments. The current electricity tariffs have been in place since Previous to 2010, tariffs remained unchanged for about seven years. A new price regulation that would allow for more regular and frequent price adjustment was proposed in 2012 but the parliament shelved the proposal. Before the financial crisis in 1998, the electricity tariff adjustment mechanism (ETAM) was in place to keep the rates aligned with movements in exchange rates and oil prices. In addition, PLN was allowed to set the tariffs and realize an 8% rate of return. The ETAM and guaranteed 8% return were abandoned during the crisis. Instead of applying an automatic adjustment, the government now prescribes the prices and provides subsidy to PLN to cover the revenue gap. The subsidy is important to PLN, especially when the Rupiah depreciates, because all of PLN s power purchasing agreements are long-term and denominated in US dollars. Moreover, the average contract price of PLN with the IPPs is higher than the regulated retail rate. Thus the two biggest power suppliers to PLN, Paiton Energi (23.1%) and Jawa Power (20%) received an average price of about US$0.083 per kwh in 2001 when PLN s average selling price was no more than US$0.078 per kwh. The price of renewable power is even higher than conventional power. Recently, the government has set the price of power generated from geothermal energy between US$0.10 and US$0.17, depending on the location of the fuel source, even as the current average retail rate is only US$ Indonesia has six main tariff categories: residential, business, industrial, social activities, government and street lights. Each category has subcategories based on maximum power installed. Residential customers are levied lower rates than other customer classes. The tariff for each category consists of a basic charge which is based on installed maximum power capacity, and a consumption charge, with progressively increasing rates. In addition, a surcharge for street lights of about 2 to 2.5% of basic and consumption charges is imposed. Some residential customers with high installed capacity are assessed 10% value added tax (VAT) but most are exempted. PLN sources oil and gas from another public utility, Pertamina, at prices indexed to the Mean of Platts Singapore (MOPS). It has the same arrangement with another public utility for coal supply. But it also has long term contracts for natural and petroleum gas with 20 other suppliers. 45 See Table IV.1. Final Report Page 70

92 The Indonesian government is currently promoting geothermal energy to raise its share from the current 2.7%. Present regulation requires geothermal power plants to remit to the government 34% of their net revenue as an all-inclusive tax (i.e., including income taxes). But recently, the government agreed not to collect taxes from companies operating geothermal plants in exchange for a production quota set every year. The estimated fiscal revenue loss in 2012 as a result of this policy is about Rp815 billion (US$85 million). Subsidy Due to the huge gap between regulated prices and PLN s costs of operation, subsidy to the public utility reached Rp93,178 billion (US$10.24 billion) in This amount represented 10% of government expenditure and 27% of total subsidy during the year. The proposed subsidy to PLN for that year was US$7.2 billion. The subsidy is calculated for each customer category as follows: the difference between the average retail price and basic allocation expenses (biaya pokok penyediaan, BPP) multiplied by sales volume (kwh). BPP is determined by the Ministry of Energy and Mineral Resources based on a formula that considers generation, transmission and distribution costs as well as system losses. It is calculated for three electric current types, i.e., low, medium and high voltage. In 2011, the BPP for low, medium and high voltage were set at 1,352, 1,113 and 1,040 rupiah per kwh, respectively. Table IV.1 allocates the subsidy received by PLN in 2011 to 19 customer categories based on the BPP and reported average retail prices. The total amount allocated was Rp84.04 billion, which is about Rp 9 billion short of the actual transfer. The difference is deemed given to PLN as additional allowance. Table IV.1 Electricity Subsidy in Indonesia, by Customer Category, 2011 Category Voltage Energy sold (MWh) Average price (Rp/kWh) BPP (Rp/kWh) Subsidy (Rp billion) S 1 L 1, , S 2 L 2,767, , , S 3 M 1,226, , R 1 L 58,275, , , R 2 L 4,337, , , R 3 L 2,495,910 1, , B 1 L 4,711, , , B 2 L 9,776,264 1, , , B 3 M 11,891, , , I 1 L 123,189 1, , I 2 L 4,093, , , I 3 M 37,705, , , I 4 H 12,802, , , P 1 L 1,433,363 1, , P 2 M 1,356, , P 3 L 3,063, , , T (Traksi) M 87, , C (Curah) M 94, , M (Multiguna) M 1,748, , Total 84, Source: Perusahaan Listrik Negara, Statistik Listrik 2011 Final Report Page 71

93 Price Schedule The customer categories in the PLN s tariff schedule relevant to the model cases are presented below. They correspond to residential, low voltage commercial, low voltage industrial and high voltage industrial, respectively. Table IV.2 Tariff Schedule in Indonesia for Selected Customer Categories Customer category Power limit (kva) Demand charge (Rp/kVA/month) Consumption charge (Rp/kWh) R-1/TR , kwh : kwh : 360 > 60 kwh : 495 B-2/TR 6.6 to 200 * Block 1: H1 x 900 Block 2: H2 x 1,380 I-2/TR 14 to 200 ** WBP (peak) : K x 800 LWBP (non-peak) : 800 kvarh : 875*** (Rp/kVArh) I-3/TR Greater ** WBP (peak) : K x 680 than 200 LWBP (non-peak) : 680 kva kvarh : 735*** (Rp/kVArh) Prepaid (Rp/kWh) 415 *Minimum charge applies. RM1 = 40 (Usage hour) x Power limit (kva) x Consumption charge Block 1 Usage hour = kwh per month / Power limit (kva) H1: Percent of economic limit on usage hour based on national average times power limit (kva) H2 : Electricity usage H1. **Minimum charge applies. RM2 = 40 (Usage hour) x Power limit (kva) x Consumption charge LWBP (non-peak) Usage hour = kwh per month / Power limit (kva) K is ratio between consumption charge of WBP (peak) and LWBP (non-peak) and subject to local electricity load. ***Reactive power charge applies if power factor is less than 85%. Source: Computation of Tariffs 1,100 To apply the tariff schedule in Table IV.2, the values of H1 and K are required, but these are not available. These are however embedded in the billing simulator found in the PLN s website ( to generate pre-tax rates. A 2.5% tax for street lighting is applied to all customer classes, while residential customers are assumed exempted from the 10% VAT. The results of the simulation are presented below. Table IV.3 Indonesian Tariffs in 2011 for the Four Model Cases RESIDENTIAL (200 kwh) Pre-tax Post-tax LOW VOLTAGE COMMERCIAL (3 MWh) Pre-tax Post-tax LOW VOLTAGE INDUSTRIAL (50 MWh) Pre-tax Post-tax In Rp 90,120 92,373 3,894,216 4,380,993 50,188,000 56,461,500 In Php , , , , Final Report Page 72

94 HIGH VOLTAGE INDUSTRIAL (200 MWh) Pre-tax Post-tax Note: Rp 1.00 = Php In Rp 170,603, ,929,410 In Php , In 2005, PLN introduced a flat-rate pre-paid option, which has been quite popular in the past two years among residential and business consumers. By 2011, PLN reported that more than 5 million consumers have shifted to the pre-paid option and a 50% increase is expected in Pre-paid option allows consumers to manage their usage of electricity. It has also helped PLN reduce their uncollected accounts. The estimated customer savings from using pre-paid option is presented below. Table IV.4 Regular vs. Prepaid Pre-tax Tariff in Indonesia (in Rupiah unless otherwise specified) Customer category Regular Tariff Prepaid Tariff % Change Residential (200 kwh) 90,120 83, Low voltage commercial (3,000 kwh) 3,894,216 3,300, Malaysia 2.1 Price Structure and Regulation The electricity market of Malaysia shares many similar features with Indonesia s. Like the Indonesian market, the Malaysian market is controlled by a vertically integrated, state-owned operator, Tenaga Nasional Berhad (TNB) that undertakes the generation, transmission and distribution of electric power. Private independent power producers (IPPs) account for about two-thirds of installed capacity. Prices are regulated and adjusted only by law. The Ministry of Energy, Water and Communications approves the tariffs submitted by TNB. The current rates took effect in June 2011; the adjustment previous to the last one was in March Both Indonesia and Malaysia have their own oil and natural gas supply, thus their power generation capacities are both concentrated on fossil fuels. In Indonesia, about two-thirds of installed capacity is oil-based; more than half of Malaysia s installed capacity is based on natural gas. Because oil and gas are indigenous to both countries, these fuels are heavily subsidized in both countries. But PLN pays Pertamina the MOPS rate for the oil supply, and receives direct transfers from the government to cover the difference between its revenues and costs. On the other hand, TNB and IPPs in Malaysia receive huge discount on the natural gas supplied by Petronas. In addition, TNB enjoys direct transfers from the government, which was about RM469 million in Thus, whereas subsidy in the Indonesian market can be measured in terms of government transfers to PLN, in Malaysia, it has to be measured in terms of both fuel discounts and direct transfers to TNB. This makes it more difficult to ascertain the actual subsidy and its impact on price in Malaysia. Official statistics on subsidies are scarce. Nonetheless, the International Energy Agency (IEA) of the Organization for Economic Cooperation and Development (OECD) estimated that the subsidy to the Malaysian electricity sector amounted to US$810 million and US$940 million in 2010 and 2011, respectively. The issue of subsidy has been at the center of policy debate in Malaysia for some years now since the launch of the 10 th Malaysia Plan for 2010 to 2015, which lays out a broad plan to Final Report Page 73

95 reduce subsidies but does not contain any specifics on its implementation. 46 According to Dato Sri Idris Jala, CEO of PEMANDU (Prime Minister s Department), the government aims to raise electricity tariffs by 2.4 sen/kwh and 1.6 sen/kwh every six months thereafter over a five-year frame. 47 This suggests a total adjustment of 18.4 sen/kwh to reduce the sector s dependence on transfers from the national government. 48 In June 2011, the average tariff was raised by 7.12%, of which 5.12% was meant to compensate for the 28% increase in the price of natural gas sold to the power sector, and the remainder to cover partially the increase in other production costs since the last tariff adjustment in June Most residential consumers were shielded from the 2011 tariff adjustment. There was no tariff increase for 3.3 million consumers considered in the lifeline band, i.e., those with monthly consumption of not more than 200 kwh. The rate for this group has been maintained at 21.8 sen/kwh since There was also no change in the tariffs paid by 1.1 million consumers with monthly consumption of 201 to 300 kwh. In all, 75% of household consumers (4.4 million consumers) were exempted from the tariff adjustment. By contrast, industrial and commercial consumers experienced an average of 8.35% adjustment in their rates. The price regulation issued in June 2011 puts in place a Fuel Cost Pass-Through (FCPT) mechanism that calls for a review of the costs of fuel (namely gas, coal and oil) every six (6) months so that any change can be passed on to consumers. The mechanism has not been put into use. Some consumers, however, continue to receive a RM20 rebate on their monthly electricity bills. This rebate, introduced in October 2008, is available only to residential customers whose monthly bills do not exceed RM20. Price Schedule Malaysia has a uniform tariff policy like Indonesia. It has seven customer categories, namely: domestic, commercial, industrial, special industrial (those with total annual electricity expenses comprising at least 5% of their total annual cost of operations), mining, street lighting, neon and floodlighting, and special agriculture. For each consumer category, except domestic or residential, the rates are further differentiated according to supply voltage, specifically: low voltage, not exceeding 1 kv; medium voltage, from 6.6 to 66 kv; and high voltage, 132 kv and above. Tariff rates are differentiated by time of use: peak, from 800H to 2200H, and off-peak, from 2200H to 800H. For each tariff category, a Minimum Monthly Charge (MMC) is set out which a consumer must pay in case his monthly electricity bill is less than the stipulated amount. Beginning September 2011, a 1% Feed-in-Tariff (FIT) for Renewable Energy (RE) Fund was added to consumers monthly bill. Domestic (residential) consumers with monthly consumption of 300 kwh and less were however exempted. The following customer classes with applicable tariff rates are relevant to the model cases. 46 Economic Planning Unit (EPU), Powerpoint presentation of Dato Sri Idris Jala, accessed at 15 November The 10 th Malaysia Plan does not provide specific details on how the subsidy reform will be implemented. Hence there is no official document bearing out this estimate. Final Report Page 74

96 Table IV.5 Tariff Schedule in Malaysia for Selected Customer Categories Unit Effective 1 March 2009 Effective 1 June 2011 Tariff A Domestic kwh sen/kwh kwh sen/kwh kwh sen/kwh Minimum monthly charge RM/month Tariff B low voltage commercial kwh sen/kwh More than 200 kwh sen/kwh 39.7* 43.0 Minimum monthly charge RM/month Tariff D low voltage industrial tariff kwh sen/kwh More than 200 kwh sen/kwh 34.8* 37.7 Minimum monthly charge RM/month Tariff E1 medium voltage general industrial For each KW of maximum demand per RM/KW month For all kwh sen/kwh Minimum monthly charge RM/month *Applies to all kwh for those with monthly consumption of more than 200 kwh. Source: Tenaga Nasional Berhad. 2.2 Computation of Tariffs During 2011, tariffs changed twice: in June, then in September when a 1% feed-in-tariff was introduced. To obtain the tariff for 2011, the averages of tariffs applicable in the following segments were taken: January to May; June to August; and September to December. The results of the simulation are shown below. All customer classes are assessed 6% VAT. Table IV.6 Malaysian Tariffs for the Four Model Cases RESIDENTIAL (200 kwh) Pre-tax Post-tax LOW VOLTAGE COMMERCIAL (3 MWh) Pre-tax Post-tax LOW VOLTAGE INDUSTRIAL (50 MWh) Pre-tax Post-tax HIGH VOLTAGE INDUSTRIAL (200 MWh) Pre-tax Post-tax Note: RM 1 = Php Singapore 3.1 Price Structure and Regulation In RM , , , , , , In Php , , , , , , Price regulation in Singapore applies only to a small segment of end-users, mostly residential, who are considered noncontestable. About three quarters of electricity users belong to the so-called contestable market where the rates are unregulated. Final Report Page 75

97 Non-contestable consumers are those whose average monthly consumption over a 12- month period is less than 10,000 kwh. They can buy electricity only from SP Services at regulated rates, which are revised quarterly by SP Services to reflect the actual cost of electricity and approved by the regulator, EMA. Contestable consumers, by comparison, may purchase electricity from a retailer, from the wholesale market through the MSSL, or directly from the wholesale market. The final rates paid by contestable consumers depend on the outcome of trading in the wholesale electricity market and their bilateral negotiations with electricity suppliers. Regardless of whom a contestable customer sources electricity service, a big component of the tariff is the Wholesale Electricity Price (WEP), which consists of the following: USEP. This is the price for energy paid by retailers and is calculated as the weighted average of the energy prices at all the off-take nodes of the Electricity network; Allocated Regulated Price (ARP). This is the cost of regulation products from the market that is shared by retailers and generators. The share of retailers is based on their metered withdrawal quantities while the share of the generators is based on their injected energy quantity. Hourly Electricity Uplift Charge (HEUC). This is the difference between the total amount received from the retailers and the total amount paid to generators for energy, reserve, and regulation products. It is typically a return to retailers of the revenue arising from the sale of energy to cover transmission losses; Monthly Electricity Uplift Charge (MEUC). This covers potential payments and refunds each month for the following: (i) cost of procuring contracted ancillary services and related costs; (ii) compensation claims and refunds; (iii) financial penalties and refunds; (iv) estimated monthly energy uplift shortfall to be recovered and/or deducted in the following calendar month; Energy Market Company (EMC) fees. The administrative costs of EMC are approved by EMA on an annual basis. Power System Operator (PSO) fees. The administrative costs of PSO are approved by EMA on an annual basis. The electricity tariff for noncontestable consumers, on the other hand, has the following components: Energy Cost. This is paid to the generating companies and is adjusted quarterly to reflect changes in fuel and nonfuel costs of power generation; Network Cost. This is paid to SP Power Assets and is reviewed annually. Currently stands at 4.78 cents per kwh, network cost was last adjusted in April 2011 when it was reduced by 2.8%; Market Support Services Fee. This is payment for the billing and metering services of the MSSL and is reviewed annually. At present, the fee is 0.22 cents per kwh. It has not been adjusted since July 2008; Market Administration and Power System Operation Fee. This is paid to the Energy market Company and the Power System Operator and is reviewed annually to recover the cost of operating the wholesale market and the power system. The fee has remained unchanged at 0.06 cents per kwh. Rebate to households As part of the Goods and Services Tax (GST) Offset Package launched in 2007, the Singapore government has been providing low- and middle-income households with vouchers that are used to offset their utilities bill. Called U-save rebate, the vouchers are received in January and July; unused rebates are rolled over to the following months. Final Report Page 76

98 The 2012 rebates were supposed to be the final tranche but the government recently announced that the rebates are now permanent. Only households living in government housing are entitled to the rebates. Those living in 1- and 2-room apartments were entitled to S$360 rebate in Table IV.7 U-save Rebates to Singapore Households (in Singapore dollars) 2013 onwards HDB 1- and 2-room HDB 3-room HDB 4-room HDB 5-room HDB Executive Source: This system is akin to lifeline discounts in the Philippines, except that it is implemented outside the pricing mechanism. In the Philippines, the discounts are extended to households whose monthly electricity consumption does not exceed a certain threshold level (which is different for each DU). The DUs recover the discounts from additional charges to households not qualifying for the discount and other customer classes. Price Schedule The EMA sets prices for five non-contestable customers classes, of which the following are relevant to the model cases developed in this study. Table IV Tariff Schedule for Selected Non-Contestable Customers in Singapore 1 st Qtr 2 nd Qtr 3 rd Qtr 4 th Qtr LOW TENSION SUPPLIES, DOMESTIC All units, S$/kWh LOW TENSION SUPPLIES, NON- DOMESTIC All units, S$/kWh HIGH TENSION SMALL (HTS) SUPPLIES Contracted capacity (S$/kW/month) Non-contracted capacity (S$/KW/month) (S$/kWh) Peak period (7.00 am to pm) Off-peak period (11.00 pm to 7.00 am) Reactive power charge S$/kVARh HIGH TENSION HIGH (HTH) SUPPLIES Contracted capacity (S$/kW/month) Non-contracted capacity (S$/KW/month) (S$/kWh) Peak period (7.00 am to pm) Off-peak period (11.00 pm to 7.00 am) Reactive power charge (S$/kVARh) Source: The fifth classification is extra high tension (EHT) supplies which has the same structure as high tension large (HTL) supplies but with lower rates. Final Report Page 77

99 3.2 Computation of Tariffs Since the actual rates paid by contestable customers are not known, the preceding schedule that applies to non-contestable customers is used to simulate the tariffs for Singapore. In applying this schedule, several assumptions have to be introduced. First, for customers classified under high tension small and high tension large supplies, which correspond to low voltage industrial and high voltage industrial cases, the energy cost is assessed by time of use. It is assumed that 60% of consumption occurs during peak hours. Second, industrial customers are assumed to contract capacity by as much as their average load. The noncontracted capacity is therefore the difference between maximum demand and average load. Thus, for low industrial voltage, the contracted capacity is assumed 69 kw, while noncontracted capacity is 176 kw. For high industrial voltage, the contracted capacity is assumed 274 kw, and uncontracted capacity, 246 kw. Third, to implement the reactive power charge, a power factor of 60% is assumed. This means that the chargeable reactive power is assumed 92 kvar for low voltage industrial and 366 kvar for high voltage industrial. A 7% GST is applied to electricity tariffs. Table IV.9 Singapore Tariffs for the Four Model Cases RESIDENTIAL (200 kwh) Pre-tax Post-tax LOW VOLTAGE COMMERCIAL (3 MWh) Pre-tax Post-tax LOW VOLTAGE INDUSTRIAL (50 MWh) Pre-tax Post-tax HIGH VOLTAGE INDUSTRIAL (200 MWh) Pre-tax Post-tax Note: S$ 1.00 = Php In S$ , , , , In Php 1, , , , , , ,549, ,657, The above calculations are based on regulated prices for non-contestable consumers. They may not apply to customers in the low and high voltage industrial cases where the assumed consumption levels, 50 and 200 MWh respectively, render those customers contestable. Consequently, it is conceivable that they pay lower than the estimated rates because of the competition among service suppliers, and therefore the tariffs shown above are upper bounds of the actual rates paid by customers in those classes. 4. Thailand 4.1 Price Structure and Regulation While the market structure of Thailand electricity sector remains traditional vertical integrated and dominated by state-owned utilities its price regulatory regime is more transparent, flexible and responsive to cost changes than the regulations in Indonesia and Malaysia. In July 2011, the Energy Regulatory Commission of Thailand (ERCT) 49 implemented a new tariff regulation that is envisioned to set the rates at more cost reflective level, while 49 This acronym is used only in this report to distinguish it from the Philippine regulator with the same name. Final Report Page 78

100 guaranteeing the financial stability of the three state-owned utilities (EGAT, MEA and PEA). The new regulation also allows for claw back to ensure that the state utilities continue to operate under their respective investment plans in cases of lags in tariff adjustment. Moreover, the scope of free electricity policy is lowered from 90 to 50 kwh per month. Thailand adopted a uniform tariff approach," which means that the same rate is applied nationwide for each customer category. To implement the policy, cross subsidization is implemented through direct financial transfers from MEA to PEA and sometimes from EGAT to PEA. Electricity tariff consists of a base rate and automatic adjustment mechanism called F t. The restructuring in 2011 changed the basis for setting the base rate and F t. These changes are described next. Base rate determination before restructuring The base rate before July 2011 reflected the investment costs of the three electricity state enterprises (EGAT, MEA and PEA) in developing power plants, transmission lines, distribution network, and energy costs based on assumptions on fuel prices, load growth, inflation and exchange rates. Two models were applied to determine the base rate: a long run marginal cost (LRMC) model and a financial model. LRMC was calculated based on the costs of generation, transmission and distribution, taking into account the time of use, system losses, voltage level, location and loss of load probability. Specific costs of providing service for every customer category were included. The underlying assumption was that the generating capacity would be expanded to satisfy increasing power demand. Some assumptions were made concerning fuel costs, EGAT s investment plan, and operating expenses. The estimated marginal cost, which varies by voltage level and location, was decomposed into energy and demand charges. The energy charge reflected the costs of generation and transmission, plus losses in the system. Transmission cost was allocated by time of use, i.e., peak and off-peak period. The demand charge represented distribution costs. In the financial model, the base tariff was set at the level that would fully compensate the three utilities for their investments and operating expenses. In this model, the base tariff was derived from the revenue requirement of each activity and each state utility to ensure financial viability, capability to expand in the future and to service debts. In order to estimate the revenue requirement, assumptions were made concerning fuel prices, inflation rates or consumer price index (CPI), efficiency improvement of each activity (X factor), investment plan, financial criteria, lump sum financial transfer, and remittances to national government. In 2005, a cap on the return on invested capital (ROIC) was introduced in tariff setting. It was set at 8.39% for EGAT and 4.8% for MEA and PEA. The remittance rates to the government for income tax and dividends were pegged at 35% of the net profit for EGAT and 40% for distribution utilities. In 2000, the X factors for the generation, transmission, and distribution and retail business were set at 5.8, 2.6 and 5.1 percent, respectively. The same X factors were used in the 2005 tariff determination, together with the coefficient of cost volume elasticity (CVE) of The only difference between the 2000 and 2005 tariff restructuring was the allowed share of nonfuel and non-power purchasing controllable operating costs to total costs which was increased from 40% in 2000 to 48% in It means that for every additional kwh sold, only 0.8 times the incremental costs per unit is allowed to be passed on to consumers. Final Report Page 79

101 Macroeconomic and market assumptions such as inflation rate, interest rate, exchange rate, and fuel prices, were also considered in both LRMC and financial models. Given the results of the LRMC and financial models, the marginal cost-based tariff was adjusted to meet the estimated revenue requirements derived from the financial model. For example, in the 2000 tariff determination, the energy charge was rescaled to 115% of marginal costs to ensure that the generation business meets its financial requirements whereas the transmission charge was rescaled to 70% of marginal cost of transmission activity. The overall impact of these rescaling was to increase tariffs relative to marginal costs at higher voltages and during off-peak hours and to reduce tariffs below marginal costs at lower voltages during peak hours. The estimated tariff consisted of bulk supply tariff (BST) that EGAT charged to both MEA and PEA, and retail tariff. The average BST during October 2005 to December 2008 was baht/kwh, which was lower than the previous BST by 3.54%. Retail electricity base tariffs were determined according to level of consumption and voltage. Thailand offered flat tariffs to most customer groups with the option to switch to Time of Use (TOU) tariffs. Hotels, guest houses and other lodging services with peak demand greater than 30 kw did not have the option of flat tariffs. MEA and PEA considered the period between 9AM 10PM weekdays, excluding public holidays, as peak (ADB, 2008). All other periods were considered off-peak. A VAT of 7% was imposed. Automatic tariff adjustment mechanism before restructuring Since the base tariff could only be changed by new regulation which was done every five years, a second component, F t, was needed to allow for tariff adjustments due to unanticipated changes in costs, demand and other factors affecting investments. This is to keep tariffs aligned to actual costs and to reduce the impact of fuel price volatility on the power utilities financial status. Over the years, the F t formula was revised to keep in step with the changing economic situation, financial conditions of state utilities, and regulatory objectives. In 2000 the F t was unbundled into generation, transmission and distribution and retailing businesses. In 2005, the F t formula was revised and simplified to two components: constant F t set at baht/kwh, and change in F t or ΔF t to account for changes in fuel costs and power purchasing prices from the time the constant F t was set. The costs of fuel and energy purchase include fuel expenses of EGAT power plants and power purchased from private producers and neighboring countries such as Laos and Malaysia. With the revised F t formula, only changes in costs of fuel and power purchased from IPPs could be passed on to consumers. F t was designed so that uncontrollable costs could be passed on by operators to consumers. After the establishment of ERCT in 2007, the same regulation was applied to F t determination, i.e., only F t was continuously adjusted. The ERCT froze F t at baht/kwh, thereby fixing F t at baht/kwh for two years. The main reason was to reduce consumers burden amidst rising oil prices, and to cover the costs of free electricity policy. However freezing F t caused huge financial burden to state utilities, particularly EGAT. Final Report Page 80

102 Base Tariff post restructuring The current base tariff levels are set based on projected financial requirements of electricity generation, transmission, distribution and retailing. The intention is for base tariff to reflect the underlying marginal costs and be fully cost-reflective. Generation rate covers the costs of EGAT s generation, power purchase from private IPPs and EGAT s internal PPAs, and foreign power purchases. Transmission and distribution charges should cover costs of transmission and distribution, use of system, energy losses and connection. The cost of system operator (as single buyer) includes costs of operation, customer services, administration, depreciation and appropriate rate of return. Retailing costs refer to costs of the meter, reading, billing and collection. EGAT s wholesale tariff structure varies progressively with voltage and time of use and is uniformly applied to MEA and PEA. Compared to 2005, the ROIC in for EGAT is lower at 7.5%, but the ROIC for MEA and PEA is higher at 5.73%. The average operating cost is estimated from the average of actual operating costs during , which includes license fees, bonus and research and development expenditures, accounting for 3 percent of net profit. The capital expenditures of the three SOEs are based on the approved investment plan by NESDB during period of Energy demand is forecasted based on the proportion of actual energy demand in the past year. Financial transfers between state utilities will be on unit basis and flexibly adjusted as actual sales and purchases occur. The financial criteria and cost-based tariff are still the basis for base tariff determination. The incentives for operators efficiency improvement are not mentioned in the policy, and thus probably neglected. There is no evidence of any mechanism to incentivize operators to improve their efficiency. Customers are still classified into 8 groups for tariff purpose, with some modifications. For example, hotel and lodging establishments are reclassified under specific business, and non-profit organizations are no longer classified with government agencies. A new classification called temporary tariff was introduced to be applied to construction of buildings or structures, special event or temporary work. Apart from retail electricity base tariff, energy charges in base tariff for direct customers was revised. The regulatory period for the implementation of the base tariff is only one year. Some operators however find this new policy as contributing to regulatory uncertainty. Automatic tariff adjustment mechanism post restructuring In 2011, F t formula was revised. F t is now classified into wholesale and retail rates. Retail F t is collected from energy users by MEA and PEA and from direct users by EGAT. Wholesale F t is collected by EGAT from MEA and PEA. Both F t will be revised quarterly. Under the new regulation, F t in May-June 2011 of baht per kwh was absorbed in the new retail base tariff so that the F t in July 2011 was readjusted and set to zero. The retail F t formula includes of fuel adjustment cost (FAC) and accumulated costs. FAC includes EGAT s fuel costs, power purchases from IPPs and SPPs and from foreign countries, and policy expenses such as free electricity. The wholesale F t formula is composed of retail F t, augmented by policy expenses incurred by MEA or PEA. Under the new F t formula, retail F t has been adjusted to near zero due to underinvestment of the three SOEs and decline in prices of natural gas. However when the costs of fuel and Final Report Page 81

103 power purchases increased, ERCT asked EGAT to partially bear the financial burden on fuel costs and power purchases and to increase retail F t up to 0.30 baht per kwh (about 50% of true retail F t ). As a result, the average retail tariffs fell. Price Schedule The base tariff schedules and F t before and after restructuring are presented in detail in the discussion of the Thailand electricity market in the accompanying volume to this report. The rates applying to specific customer categories relevant to the model cases are shown below. Table IV.10 Tariff Schedule in Thailand for Selected Customer Categories Before July 2011 Post July 2011 RESIDENTIAL SERVICE Consumption exceeding 150 kwh per month Energy Charge (Baht/kWh) First 150 kwh Next 250 kwh Over 400 kwh Service Charge (Baht/month) SMALL GENERAL SERVICE Of voltage level less than 22 kv Energy Charge (Baht/kWh) First 150 kwh Next 250 kwh Over 400 kwh Service Charge (Baht/month) MEDIUM GENERAL SERVICE At voltage level less than 22 kv/ Below 12 kv Demand Charge (Baht/kW) Energy Charge (Baht/kWh) Service Charge Power Factor Charge *** At voltage level less than 22 kv/ kv Demand Charge (Baht/kW) Energy Charge (Baht/kWh) Service Charge Power Factor Charge *** AUTOMATIC TARIFF ADJUSTMENT F t (Baht/kWh) January April May June July September October December ***The 2011 tariff restructuring added a power factor charge (PFC) in all categories except residential and small general services. For medium general services, PFC is assessed on consumers with a lagging power factor, i.e., those with maximum 15-minute reactive power demand (kilovar demand) exceeding 61.97% of its maximum 15-minute active power demand (kilowatt demand) during a monthly billing period. Each kilovar in excess is charged Baht 56.07, determined to the nearest whole kilovar, discarding the fraction of 0.5 kilovar. A few points must be considered in applying these rates. First, the above tariffs are flat rates. There are also TOU rates for each of these categories, which however are not considered in this exercise. Second, one of the changes in the 2011 tariff restructuring is the introduction of subcategories in medium general services for those connected to low voltage wires, i.e., less than 22 kv. Whereas it was one subcategory before restructuring, it has been broken up into below 12 kv and 12 to 24 kv. The low voltage industrial case corresponds to the below 12 kv subcategory, while the high voltage industrial matches the 12 to 24 kv subcategory. Finally, the automatic tariff adjustment applies to all customer categories. Final Report Page 82

104 4.2 Computation of Tariffs The application of power factor charge requires further assumptions. The maximum demand levels for low- and high- voltage industrial customers are set at 195 and 520 kw, respectively. Assuming a 60% power factor, the maximum reactive power for these cases are 260 and 694 kvar, respectively. We take the average of tariffs estimated using rates before and after July restructuring to obtain the representative tariff during the year. The results are shown below. Table IV.11 Thailand Tariffs for the Four Model Cases RESIDENTIAL (200 kwh) Pre-tax Post-tax LOW VOLTAGE COMMERCIAL (3 MWh) Pre-tax Post-tax LOW VOLTAGE INDUSTRIAL (50 MWh) Pre-tax Post-tax HIGH VOLTAGE INDUSTRIAL (200 MWh) Pre-tax Post-tax Note: Baht 1 = Php In Baht , , , , , , In Php , , , , , The above estimation also confirms that the 2011 tariff restructuring has the effect of lowering tariffs for residential customers, while raising tariffs for industrial. The following compares the pre-tax tariffs in the first and second half of 2011 in the four model cases. Table IV.12 Effects of Thailand Tariff Restructuring on Consumers (in Baht) First Sem., 2011 Second Sem., 2011 Change (%) Residential Low voltage commercial Low voltage industrial 175, , High voltage industrial 644, , Final Report Page 83

105 V. Benchmarking of Philippine Electricity Tariffs All benchmarking exercises involving electricity prices suffer one major difficulty, namely, while electricity is a homogeneous commodity, there is no international reference price. Not only because electricity still remains largely non-tradable, but also the costs of delivering to end users are influenced by a wide range of factors, not all are tractable. It is well recognized that electricity prices vary between countries, within a country, and even within a distribution network. In traditionally regulated monopoly markets, electricity tariffs are usually differentiated by customer class, i.e., residential, commercial and industrial, but this is not sufficient to capture real differences in costs of providing electricity services to different types and conditions of end-users. Indeed, the costs of service for customers belonging to the same customer class can vary by location, time-of-day, capacity or nature of the supply circuit, among others. In its simplest form, benchmarking of electricity tariffs involves comparing average tariffs in countries, expressed in US dollars. While convenient, it only provides a sketchy, if not distorted, view of the differences in real burden borne by end-users. To obtain more useful results, actual tariffs must be adjusted to take into account fluctuations in market exchange rates, differences in purchasing power, government subsidies, and retail discounts that are often available in deregulated and competitive markets. This section compares Philippine electricity tariffs with other ASEAN economies based on the four model cases constructed in Section I. The objective is to compare not just retail prices, but also the costs of service to the extent they can be discerned from available prices and information about markets and regulation in the economies covered in this study. For this purpose, retail tariffs are adjusted for factors that drive a wedge between prices and costs, namely taxes, transitory tariff components and subsidies. Tariffs are therefore compared at pre-tax levels after eliminating subsidies and transitory tariff components. It should be emphasized that notwithstanding these adjustments, there is no claim that the resulting tariffs represent the economic costs of supplying electricity in these economies. The transfers from the national government to public utilities, usually interpreted as subsidy may be more or less than necessary to cover the economic costs of production. It is not unusual that state utilities are made to absorb losses in pursuit of social objectives, or that they are sustained by their governments despite their inefficiencies. This is in fact the case for the subsidy presented in Table IV.1 for Indonesia. The amount that is labeled as subsidy represents transfers from the national government to PLN. It is based on the difference between the amount that the government deemed to be the costs of service (i.e., the BPP) and regulated price. But the bases for these cost estimates are unclear, and they are differentiated only by the supply of circuit, i.e., low, medium and high voltage. Locational differences, which can affect costs significantly, are ignored. Clearly, the BPPs are more relevant to the Indonesian government in determining the transfers than as cost reference, and hence they do not reveal the actual costs of service. To facilitate comparison, the adjusted tariffs are converted to a common currency, customarily the US dollar. However, market exchange rates do not always represent the true value of the national currency since they are influenced by a host of factors including speculation, interest rate, capital flows and government intervention. As a result, at any given time, the national currency may be under or overvalued with respect to a reference currency. One consequence of this is exchange rate converted tariffs are usually misleading as to their relative sizes. When the national currency is undervalued, say against the dollar, the dollar-denominated tariff would appear smaller than they actually are. The opposite is true when the currency is overvalued. Final Report Page 84

106 A currency is under- or over- valued when the market exchange rate is not aligned with the currency s purchasing power. Thus to ensure that the use of market exchange rate does not distort the comparison, the tariffs are converted to a common currency that equalize the purchasing power of the different national currencies. That common currency with purchasing power parity is the PPP dollar. In this exercise, we use the PPP dollar published by the World Bank. The PPP conversion factor is the number of units of a country s currency required to buy the same amounts of goods and services in the domestic market as a U.S. dollar could buy in the U.S. 51 In 2011, the market exchange rates and conversion factor for PPP dollar are given below. Table V.1 Conversion Factors for Local Currency Units PHL SGP THA INA MAL US dollars, average , in 2011 PPP$, , Cross-peso, average in Source: World Bank online database for US dollars and PPP$; Bangko Sentral ng Pilipinas for crosspeso rates. In the next subsections, we draw from the results in Sections II and III. At the first level, we compare retail prices or what a consumer would pay, taxes included, for a specified level of monthly consumption in These are labeled as post-tax prices in Section III. We use the base composite prices, derived in Section II, to represent Philippine retail tariffs with taxes. To recall, these are composite prices after removing noise or transitory tariff components. Then we compare tariffs after removing taxes, labeled as pre-tax prices in Section III. At the third level of comparison, the calculated tariffs are adjusted for subsidies. The discussion in Section III presented subsidy estimates in Indonesia and Malaysia but none in Thailand. This is because while there are transfers among state utilities (from EGAT to PEA and from MEA to PEA), there is none from the national government to any of the state utilities. In the absence of fiscal burden, there is no explicit subsidy in the electricity market in Thailand. Yet more than two-thirds of electricity in Thailand is generated from natural gas, all of which are sourced locally. If the costs ascribe to indigenous natural gas in electricity production were below international price, then there could be rents accruing to electricity consumers equivalent to the opportunity cost of pricing domestic natural gas below world prices. This is difficult to verify, much less estimate, without detailed knowledge of the generation costs. However, the International Energy Agency (IEA) provides estimates of subsidies in the electricity sector for a number of countries, including those covered in this study. IEA uses the price-gap approach which compares the prices paid by consumers with reference prices, i.e., prices that would prevail in a competitive market. The difference between consumer and reference prices is deemed as the subsidy. When a commodity is imported, estimating the subsidy through the price-gap approach is straightforward. It is the difference between the import expenditure and the price at which the imported commodity is sold in the domestic market. But for an exported commodity, the 51 The ratio of PPP conversion factor to market exchange rate is the national price level. It indicates how many dollars are needed to buy a dollar s worth of goods in the domestic market as compared to the U.S. Thus a ratio of 0.6 suggests that a dollar s worth of goods purchased in the U.S. can be purchased in the domestic market for only 60 US cents. Final Report Page 85

107 subsidy is implicit the difference between world price which the commodity would have commanded if exported, and domestic price. The subsidy in this case is the opportunity cost of pricing the commodity below world market level, or the rent that could be recovered if domestic consumers paid world prices. In most cases, an economy exports as well as imports the same commodity; in which case, the subsidy is a combination of opportunity cost and uncovered expenditure. One consequence of applying this approach is that resource-rich countries tend to rank high in providing subsidies. In 2011, for example, the top five countries in providing subsidies on fossil fuel consumption were Iran, Saudi Arabia, Russia, India and China. This is believed to be an artifact of interpreting subsidy as the difference between international and domestic prices. Critics contend that domestic prices for resources that are abundant in these countries are low because the supply is indigenous. It is argued that the appropriate reference price should be production cost, rather than international price. For these resource-rich countries, domestic prices are kept close to production costs, rather than to international prices, so that the resources could be deployed in the local market to serve some national objective. That purpose is said to be sufficient to compensate for any notional loss incurred as a result of pricing the resource below international price. Setting aside this conceptual debate, measuring subsidy in the electricity market poses yet another challenge. That is, since electricity is not extensively traded, there is no world market or international reference price that can be used to apply the price-gap approach. Nonetheless, the IEA produces a reference price for electricity out of its estimate of generation, transmission and distribution costs of an efficient network. The generation cost is based on international trade prices of fossil fuels and average fuel efficiencies for power generation. It is capped at the levelized cost of a combined-cycle gas turbine (CCGT) to avoid over-estimation. An allowance of US$15/MWh and $40/MWh are added for transmission and distribution costs to industrial and residential consumers, respectively. Since the reference price that comes out from this approach is expectedly low since it is purportedly based on most efficient production, the estimated subsidy tends to be conservative or smaller than the true gap between actual revenues of the utilities and their economic costs. Hence, one may consider the IEA s estimate as lower bound to the true opportunity cost. This probably explains why the estimate for Indonesia, shown in Table V.2, is nearly half of the transfers to PLN in 2011 (US$10.24 billion). IEA estimates subsidy for 37 economies, including the economies covered in this study except Singapore. The estimated subsidy for the Philippine electricity market is nil during the five-year period. Table V.2 IEA Estimates of Electricity Subsidy in Selected ASEAN Economies (in billion US dollars) Indonesia Malaysia Thailand Brunei Vietnam From the foregoing and applying electricity consumption levels, the implicit subsidies per kwh in 2011 for Indonesia, Malaysia and Thailand are Rp308.64, 2.93 sen and 1.17 baht (3.85, 0.91 and 3.53 US cents), respectively. These estimates are applied below to analyze the extent subsidies have held down tariffs in these economies. Final Report Page 86

108 1. Impact of Taxes The next table compares electricity tariffs with and without taxes in the five countries. It shows that the Philippine residential and commercial tariffs are the highest even after taxes are removed. Yet Singapore industrial tariffs are higher than the Philippines, which however should be taken with caution since the rates applied in Singapore were for noncontestable consumers notwithstanding that the assumed levels of consumption (50 and 200 MWh for low and high voltage industrial consumers, respectively) would have rendered the users contestable. Table V.3 Comparison of Electricity Tariffs after Removing Taxes (in US dollars) PHL SGP INA MAL THA In US dollar Tariffs with taxes Residential Commercial Low voltage Industrial 9, , , , , High voltage Industrial 37, , , , , Pre-tax tariffs Residential Commercial Low voltage Industrial 8, , , , , High voltage Industrial 34, , , , , Pre-tax per kwh Residential Commercial Low voltage Industrial High voltage Industrial Nonetheless, the results are consistent with the findings of IEC. First, the Philippine residential tariff is the highest in the cohort. Second, the difference between Philippine and Singapore pre-tax residential tariffs is practically nil about 0.1%. For commercial tariffs, the difference is a bit larger but still marginal at 3.4%. In contrast, the Philippine residential tariff is a multiple of the tariffs in the other economies. Specifically, the Philippine tariff is four, three and two times the tariffs of Indonesia, Malaysia and Thailand, respectively. In other customer classes, however, the differences are not as stark. In commercial tariffs, for instance, the Philippine rate is 44, 56 and 70 percent more than Indonesia s, Malaysia s and Thailand s. It is evident why the tariff differentials are much larger in residential than in other customer classes. The Philippine and Singapore rate structures are more consistent with costs of supply, i.e., residential customers are charged the highest per kwh, while high voltage industrial customers pay the least, since transmission and distribution costs are higher for residential than industrial. In the regulated markets, on the other hand, residential tariffs are deliberately kept low in fact the lowest on per kwh basis among customer classes. Final Report Page 87

109 2. Impact of Subsidies Eliminating subsidies keeps Philippine tariffs still above but closer to the regulated rates. In residential class, the Philippine rate is 2.4, 2.6, and 1.5 times the rate in Indonesia, Malaysia and Thailand, respectively. For commercial tariffs, the tariff differentials are reduced to 16, 46 and 30 percent, respectively. Table V.4 Comparison of Electricity Tariffs after Removing Subsidies (in US dollars) PHL SGP INA MAL THA Pre-tax tariffs after removing subsidies Residential Commercial Low voltage Industrial 8, , , , , High voltage Industrial 34, , , , , % change due to removal of subsidies Residential Commercial Low voltage Industrial High voltage Industrial The above table also shows the effective subsidy rates in the regulated markets. Because of the implicit subsidy, Indonesian residential customers are charged 69% less than the unsubsidized rates. The subsidies in Malaysia are relatively moderate, just ranging from 7 to 13 percent, whereas they are more than 30 percent in all customer classes in Thailand. 3. Impact of Price Differences The two preceding sections compare electricity tariffs in US dollars, using average market exchange rates in As explained, a fair comparison of tariffs should take account of differences in purchasing power that are not captured by market exchange rates. This necessitates converting the local currency denominated tariffs to a common currency that has the same purchasing power. The PPP conversion factor translates the local currency into units that are able to command the same amount of goods and services in the local markets as they would in the U.S. If no account is taken of the differences in price levels, tariffs in countries with generally high price levels will be overstated, while those in countries with generally low prices will be understated. Table V.5 Comparison of Electricity Tariffs after Adjusting for Price Differences (in PPP dollars) PHL SGP INA MAL THA Residential Commercial 1, Low voltage Industrial 15, , , , , High voltage Industrial 59, , , , , Per kwh Residential Commercial Low voltage Industrial Final Report Page 88

110 PHL SGP INA MAL THA High voltage Industrial After converting the pre-tax, no subsidy tariffs (in Table V.4) to PPP dollars, the relative tariff ranking remained the same for the Philippines and Thailand. Philippine residential tariff is still 1.5 times the residential rate in Thailand, while Philippine commercial tariff is still 30% above Thailand s. On the other hand, Philippine residential tariff is now 3.1 times that of Indonesia s, compared to 2.4 times using market exchange rates. Similarly, Philippine commercial tariff is 58% more than Malaysia s, compared to 46% using market exchange rate. But the relative tariffs of the Philippines and Singapore changed significantly with the PPP conversion. Philippine electricity tariff is now higher than Singapore s by 40%, 48%, 24% and 37% for residential, commercial, low voltage industrial and high voltage industrial classes, respectively. This result is not unexpected since the price levels in Singapore are generally higher than in the Philippines and also closer to the price level in the U.S. When this price level difference is removed, the Philippine tariff would be adjusted upwards from its nominal level more than Singapore s, hence the result. Therefore, in nominal terms, the Philippine electricity tariffs appear closer to Singapore s, but when adjusted in real terms, the former are decidedly higher than the latter. This result has important implications on the findings of IEC, namely that Philippines tariffs are closer to those of developed than developing countries. The tariffs in IEC s study are expressed in nominal US dollars. If the tariffs were expressed in PPP dollars instead, i.e., adjusted for price level differences, the rankings would be different, with Philippine prices moving several notches up the ladder. 4. Synthesis Taken together, the evidence suggests that electricity tariffs in the Philippines are unambiguously higher than in regulated markets in the region, even after adjusting for taxes, subsidies and purchasing power. Yet the tariff differentials vary by customer classes widest in residential but much narrower in other classes. As market structure affects price behavior, it can be argued that the Philippines should be compared only with economies having similar industry structure. In this study, the only suitable comparator is Singapore. But the fact that Philippine tariffs are close to Singapore s provides little comfort because of the wide differences in incomes and purchasing power of customers in these two economies. Final Report Page 89

111 VI. Policy Simulations Despite finding Philippine electricity rates (represented by MERALCO s tariffs) much higher than those prevailing in other countries of similar level of development, the IEC asserted that Philippine tariffs are fair and reasonable. The report notes that the current tariff levels merely reflect the high intrinsic cost of supplying electricity in the Philippines. In support of its conclusion, the IEC cites that (i) the generation charge is close to the estimated LRMC of wholesale energy in Luzon; (ii) the transmission charge can be explained by the unique characteristics of the network due to geography and cross-subsidy to non-meralco consumers; and (iii) the distribution, taxes and other charges are comparable with those in other markets. One way of verifying if the current tariff levels are indeed a product of high supply costs is to simulate reasonable changes in policies to determine their impact on prices. If sensible and viable policy adjustments could not materially change prices, then wrong policies can be ruled out as culprits to high prices. It then follows that the actual costs of supplying electricity are probably irreducible at least from policymaking perspective hence prices can only be brought down by increasing supply or by artificial price reduction through distortionary and inefficient means. Several policy changes have been proposed in the House of Representatives and Senate aimed at lowering electricity tariffs, as enumerated below. This section simulates some of these proposed changes. The aim is not to evaluate their viability or appropriateness but to determine how much a policy change can bring down current tariff levels. Many of these proposed policy changes have fiscal implications, and thus the extent these measures are able to reduce electricity tariffs must be evaluated against the loss of government revenues. However, comparing the social gains from lower electricity tariffs and social costs due to loss of fiscal revenues is beyond the scope of this study. Hence, the simulations do not intend to pass judgment on the social desirability of the measures. Rather, they are merely meant to verify if existing policies are the immediate cause of high tariff levels, and hence a change in policies could impact on tariff levels. Table VI.1 Some Proposed Legislations to Lower Electricity Tariffs Short Title Bill Number Salient Provision Electricity Rate Reduction Act of 2010 Franchise Tax Amendment to Section 109(1) of the National Internal Revenue Code of 1997 Amendment to Republic Act No. 7832, otherwise known as Anti-Electricity and Electric Transmission Lines/Materials, Pilferage Act of 1994 Downstream Natural Gas Industry of 2010 Amendment to Section 108 of the National Internal Revenue Code of 1997 SBN2; HB01585; HB03181; HB04501; SBN3; HB01584; HB04436; HB04514; SBN2159; HB04507; HB04722 SBN2911 HB00789; HB02477; HB02980; HB01625 HB02630 Reducing electricity rates by lowering government s share in the discovery, exploration, development and production of indigenous sources of energy from the current rate of 60% to 3% of net proceeds (gross proceeds from sale of electricity minus expenses allowed to be recovered) Imposing 3% franchise tax on gross distribution income (gross income by distribution utilities minus generation and transmission charges passed, and excluding all universal and other charges ERC decides to pass on to consumers ) in lieu of all other taxes, fees, and charges imposed by the government Exempting residential consumers with 250 kwh or less electricity consumption from payment of VAT Removing recoverable rate of system losses Imposing 2% franchise tax on transmission and distribution of natural gas in lieu of all other taxes; supply of natural gas to contestable market is subject to excise tax. Exempting from payment of VAT generation companies, regardless of source; transmission of electricity by the National Transmission Corporation and its concessionaires, and distribution Final Report Page 90

112 Short Title Bill Number Salient Provision by distribution utilities, regardless of consumption and costumer class Exempting from payment of VAT the sale or importation of machinery or equipment directly used in generation, transmission and distribution of electricity Electricity Bill Subsidy of 2010 HB03915 Grant of 50% subsidy on all charges under 20 kwh for poor households, the bill evenly split between national and local government. Qualified are poor households (as determined on the barangay level by social research or other surveys) with consumption under 20 kwh per month Imposing an aggregate and uniform five centavos tax per kwh sold Value-Added Tax Rate Reduction on Oil, Electricity and Water Services of 2012 HB04502 HB06416 Imposing on DUs franchise and business (tax) permit of P0.05/kWh of electricity sold in lieu of franchise and business taxes, duties and fees, and charges of other kinds collected by government Reducing VAT from 12% to 6% on petroleum products and electric utilities The scenarios explored below involve tax restructuring, elimination of subsidies, redistribution of royalties from indigenous fuels, use of historical instead of current asset values in calculating regulated tariffs for distribution, and shifting ECs from cash-based to performance-based regulation. All policy simulations use the base composite prices (derived in Section II.5.2) as reference case. Consequently, the impact of a policy measure is evaluated in terms of the changes in the base prices when the measure is implemented. 1. Components of Base Composite Price Policy proposals aimed at lowering electricity tariffs are understandably targeted at elements that are susceptible to intervention. With the restructuring of the industry, tariff elements for which regulation has been relinquished can no longer be subject to intervention without backsliding from the market reforms. This explains why most proposals relate to taxes, and none to prices of generated electricity that are subject to commercial negotiations between the generation and distribution utilities, although generation costs account for no less than half of the tariffs in all customer classes. A decomposition of base composite prices into various tariff elements provides an indication of the potential impact of suggested proposals on final tariff levels. Table VI.2 Composition of Base Component Prices by Customer Class (in percent, except price in Philippine pesos) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial Base composite price 1, , , ,615, of which: Generation Transmission Distribution Supply Metering System loss Universal charges Subsidy VAT Other taxes Final Report Page 91

113 2. Restructuring Taxes It has been pointed out that the electricity sector is heavily taxed, as it is subject to various taxes some national, others local at different stages of production. Several proposals have been put forward in the legislative body to restructure the taxes imposed on the sector. In particular, HB 1625 and HB 2630 propose total VAT exemption for the electricity sector, whereas HB 6416 suggests a reduction of VAT from 12% to 6%. On the other hand, the Franchise Tax Bill seeks to replace VAT and other taxes with 3% franchise tax on gross distribution income. Conversely, VAT could be made to replace all other taxes similar to the tax structure in other ASEAN electricity markets. Since the effective tax rate computed in II.24 is about 9%, an almost revenue neutral measure is to impose an equivalent VAT in lieu of all other taxes. The impact of each of these measures on tariffs is as follow. 2.1 Zero VAT Table VI.3 presents the base composite prices without the VAT. This should be compared with the base composite prices with VAT in Table II.21. The effects of the complete removal of VAT are shown in Table VI.4. It shows a lowering of electricity tariffs by an average of 8%. Some franchise areas, however, have more tax relief than others since the generation and distribution of power sourced from renewables are already VAT-exempt. It follows that DUs sourcing more of their power from renewables will benefit less from the exemption than those sourcing from fossil fuels. Thus, the reductions are larger from franchise areas in Luzon than in Visayas and Mindanao where geothermal and hydro are the dominant sources of power, respectively. Table VI.3 Base Composite Prices without VAT (in Philippine peso) Low voltage Low voltage High voltage Residential Commercial Industrial ( 000) Industrial ( 000) NCR 1, , , CAR 1, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 1, , V 1, , , Luzon 1, , , VI 1, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , Final Report Page 92

114 Region IVB, which has the highest tariffs post-tax, is expected to have the largest cuts in rates, while the tariffs in Region VIII, which has one of the lowest tariffs post-tax, are least affected. Consequently, the removal of VAT reduces the tariff differentials across major islands and regions. But an important factor to consider is that apart from the loss of tax revenues, a VAT exemption applied to all regardless of fuel source negates the incentives to use renewables. This probably becomes less an issue when the other incentives afforded by the Renewable Energy Act take effect. Table VI.4 Impact of Removing VAT on Base Composite Prices (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR (8.76) (8.22) (8.24) (8.50) CAR (8.51) (8.55) (8.35) (9.70) I (7.96) (8.22) (7.81) (8.14) II (6.41) (5.24) (7.83) (7.79) III (7.71) (7.99) (5.79) (6.76) IVA (5.52) (4.46) (6.35) (2.58) IVB (10.21) (10.44) (10.52) V (5.41) (4.99) (3.98) (4.27) Luzon (8.45) (8.10) (8.05) (8.19) VI (6.78) (5.66) (10.02) (9.91) VII (7.54) (7.22) (6.72) (6.78) VIII (3.96) (2.72) (3.03) (2.09) Visayas (6.72) (6.18) (6.95) (6.90) IX (6.78) (5.67) (6.10) (5.55) X (7.23) (6.53) (5.46) (5.90) XI (5.32) (5.08) (5.65) (1.78) XII (4.31) (4.71) (3.44) (4.20) ARMM (4.90) (11.73) (20.65) CARAGA (5.54) (4.83) (3.98) (4.34) Mindanao (6.30) (5.90) (5.50) (5.20) All regions (8.10) (7.88) (7.51) (7.62) 2.2 Six-percent VAT To simulate the scenario where a 6% VAT substitutes for all other taxes, the VAT rate is applied to the pre-tax base price (i.e., actual tariff less temporary adjustments, VAT and other taxes) after removing tariff components that are not subject to VAT, namely transmission, franchise benefits to host communities, universal charges and senior citizens discount. Then the estimated VAT and non-vat tariff components are added back to the pre-tax base price. A composite price is estimated from these VAT-inclusive base prices, producing the tariff schedule in Table VI.5. Table VI.5 Base Composite Prices with Six-Percent VAT Substituting All Taxes (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 1, , , CAR 1, , , I 1, , , II 1, , , III 1, , , IVA 1, , , Final Report Page 93

115 Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) IVB 2, , V 1, , , Luzon 1, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , The changes in base composite prices are presented in Table VI.6. Generally, the substitution of all taxes with 6% VAT will lower tariffs across regions and customer classes, except in a handful of cases where the effective tax rates (see Table II.24) are below 6%, such as in Region VIII for all customer classes, and residential tariffs in Region XII and CARAGA. Overall, residential and commercial tariffs can be expected to decline by 3.7% and industrial tariffs, by 3.3%. Table VI.6 Impact on Base Composite Prices of Substituting All Taxes with Six-Percent VAT (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR (4.42) (4.14) (4.10) (4.22) CAR (3.90) (3.96) (4.00) (5.34) I (3.47) (3.80) (3.62) (3.81) II (1.67) (0.49) (3.31) (3.72) III (3.15) (3.59) (1.34) (2.28) IVA (0.63) 0.43 (1.70) 1.75 IVB (4.91) (5.17) (5.24) V (0.45) (0.13) Luzon (4.04) (3.97) (3.88) (3.89) VI (1.96) (0.76) (5.35) (5.19) VII (3.07) (2.79) (2.36) (2.41) VIII Visayas (2.09) (1.58) (2.55) (2.48) IX (2.31) (1.46) (1.84) (1.30) X (3.12) (2.46) (1.74) (2.08) XI (0.98) (0.79) (1.53) 2.65 XII 0.22 (0.26) 0.68 (0.33) ARMM 0.03 (8.15) (17.65) CARAGA (1.32) (0.57) 0.04 (0.27) Mindanao (2.00) (1.72) (1.64) (1.17) All regions (3.68) (3.72) (3.32) (3.33) Final Report Page 94

116 2.3 Almost Revenue-Neutral VAT In other ASEAN electricity markets, including Singapore, VAT is levied on the final price for easier administration. It is also the only tax that is allowed to be passed on to consumers. In contrast, in the Philippines, various taxes levied on utilities are recognized as pass through costs. This has resulted in confusion as well as difficulty of ascertaining the real magnitude of taxes embodied in electricity tariffs. This scenario explores a uniform VAT rate that could substitute for all taxes on electricity, with minimal impact on fiscal revenues. Accordingly, average tariffs are not expected to change significantly. That tax rate is estimated at 10.5%. The resulting tariffs are given below. Table VI.7 Base Composite Prices with Almost Revenue-Neutral VAT Replacing All Taxes (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 2, , , Luzon 2, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , On average, end-users tariffs are almost unaffected by the tax restructuring. Residential and commercial tariffs are expected to fall by 0.08 and 0.29 percent, respectively, while industrial tariffs may increase by 0.2 percent. The impact on individual regions are however different. Relatively high tariff regions such as NCR are given some relief; the opposite applies to relatively low tariff regions in Visayas and Mindanao. Thus, in addition to simplifying tax administration, a uniform VAT rate reduces the tariff differentials. Table VI.8 Impact on Base Composite Prices of Replacing All Taxes with Almost Revenue- Neutral VAT (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR (0.82) (0.75) (0.66) (0.66) CAR (0.44) (0.51) (0.74) (2.06) I 0.09 (0.24) (0.19) (0.32) Final Report Page 95

117 Residential Low voltage Commercial Low voltage Industrial High voltage Industrial II (0.63) III 0.42 (0.06) IVA IVB (0.93) (1.22) (1.28) V Luzon (0.44) (0.55) (0.43) (0.35) VI (1.42) (1.26) VII VIII Visayas IX X XI XII ARMM 3.72 (5.46) (15.39) CARAGA Mindanao All regions (0.08) (0.29) Franchise Tax Another proposal to simplify tax as well as to lower tariffs is to replace all taxes with 3% franchise tax on gross distribution income. To obtain the resulting tariffs under this scenario, the proposed franchise tax is applied to the sum of distribution, supply, metering and system loss components. The tax is then added to the pre-tax base price, producing the schedule below. Table VI.9 Base Composite Prices with Franchise Tax Replacing All Taxes (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 1, , , CAR 1, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 1, , , Luzon 1, , , VI 1, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , Final Report Page 96

118 Significantly, this policy measure has nearly the same impact on tariffs as a zero VAT. As shown in Table V.10, average tariffs are expected to fall between 7.5% and 7.7% depending on customer class, versus between 7.5% and 8.1% with zero VAT. Like in other scenarios imposing a uniform tax rate, the replacement of all taxes with a franchise tax reduces the tariff differential, as cuts in tariffs are largest in Luzon (about 8%) and least in Mindanao (about 5%). Table VI.10 Impact on Base Composite Prices of Substituting All Taxes with Franchise Tax (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR (8.40) (7.96) (8.13) (8.59) CAR (7.63) (7.97) (7.75) (9.18) I (7.41) (7.92) (7.63) (7.95) II (5.99) (4.67) (7.25) (7.31) III (7.16) (7.72) (5.51) (6.55) IVA (4.67) (3.84) (5.88) (2.25) IVB (9.35) (9.92) (9.99) V (4.47) (4.34) (3.37) (3.67) Luzon (8.03) (7.83) (7.93) (8.24) VI (6.19) (5.31) (10.08) (9.98) VII (7.17) (6.94) (6.72) (6.77) VIII (2.98) (2.08) (2.31) (1.49) Visayas (6.19) (5.84) (6.95) (6.87) IX (5.72) (5.11) (5.46) (4.97) X (6.80) (6.25) (5.51) (5.93) XI (4.46) (4.39) (5.11) (1.31) XII (3.30) (3.98) (2.73) (3.62) ARMM (3.91) (11.20) (20.19) CARAGA (4.82) (4.33) (3.43) (3.93) Mindanao (5.55) (5.45) (5.35) (4.93) All regions (7.65) (7.60) (7.41) (7.62) 3. Eliminating Subsidies 3.1 Lifeline Discounts The lifeline rate is a subsidy given to marginalized or low-income consumers, the provision of which is stipulated in EPIRA for a 10-year period. When the mandatory period expired in June 2011, the legislative body extended the scheme for another 10 years through Republic Act The threshold level, i.e., maximum consumption covered by the discount, and the discount rates applied by each DU have to be approved by the ERC, based on the income and consumption pattern of customers in a franchised area. Since the scheme is a crosssubsidy by customers whose consumption exceeds the threshold level to customers with consumption at or below the threshold, the regulator must ensure that there would be no under- or over recovery of discounts. Information on the approved lifeline discount schedule is available for 136 DUs and is summarized in Figure V.1 below. Of the 136 DUs, only two are not mandated to extend lifeline discounts: Subic Enerzone Corporation and Clark Electric Distribution Corporation (CEDC). Only four DUs provide discounts for up to 100-kWh consumption, namely: MERALCO, DLPC, CEPALCO and ILPI. About 70% (96 DUs) provide discounts to consumers with 25 kwh or less monthly usage. Final Report Page 97

119 Number of DUs Challenges in Pricing Electric Power Services in Selected ASEAN Countries Figure VI.1 Histogram of Lifeline Discounts Maximum kwh covered by lifeline The discount rate is applied to the sum of the generation, transmission, system loss, distribution, supply and metering charge components of the residential bills. Exempted from application of lifeline discount is the fixed metering charge (Php5.00/month) of residential customers consuming up 20 kwh. MERALCO has 2 million customers (45% of million residential customers base) with average monthly consumption of 100 kwh or below in The average residential monthly consumption in the MERALCO franchise area is 180 kwh. More than 300,000 residential customers were consuming less than 20 kwh a month and therefore receiving 100% lifeline discount. In March 2011, the penalty to the subsidizing customers in the MERALCO franchise area was Php per kwh. In general customers of PIOUs have higher incomes than those of ECs. Because the scheme is a cross-subsidy within a DU, PIOUs generally have higher threshold levels and larger discount rates. It follows that the poor in PIOUs with higher-income customer base tend to benefit more than the poor in ECs with lower-income customer base. This invites inquiry into the design of the scheme, i.e., whether the mode of financing the discount is economically sensible and whether it is effective in targeting support to the poor. At monthly consumption of 20 kwh or less, most PIOUs offer discounts of either 100% or 50%. In contrast, the discounts offered by ECs for the same consumption range are between 10% and 60%. In any case, the discount declines as consumption increases. For example, MERALCO applies 100% discount to the first 20 kwh; 50% to the next 30 kwh; 35% to the 20 kwh thereafter; and 20% to the succeeding 30 kwh. Even as the scheme is continued until 2021, there have been several proposals to reform it. One proposal is to lower the threshold level so as to prevent the non-poor with low consumption level from receiving the discount. Another proposal is to change the financing scheme from cross-subsidization to universal charge. To simulate these proposals, one would need the income and consumption profile of customers in each DU. Since this information is not available, it is only possible to simulate the effect of completely removing the discounts. The new base composite prices sans lifeline discounts are given below. Final Report Page 98

120 Table VI.11 Base Composite Prices After Removing Lifeline Discounts (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 1, , , Luzon 1, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , As the next Table shows, the removal of lifeline discounts will lower the composite prices even for residential customers. Bigger benefits from the removal of the discounts redound to the subsidizing customers, i.e., commercial and industrial, as would be expected. Thus, high voltage industrial tariffs will fall by as much as 1.56%, compared to 1.28% for residential tariffs. Table VI.12 Impact on Base Composite Price of Removing Lifeline Discounts (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR (1.47) (1.40) (1.56) (1.81) CAR (0.90) (0.99) (0.97) (1.48) I (0.92) (1.05) (1.26) (1.25) II (0.90) (0.95) (1.19) (1.17) III (0.74) (0.72) (1.09) (0.87) IVA (0.78) (0.85) (1.07) (0.89) IVB (0.87) (1.02) (1.01) V (1.15) (1.27) (2.09) (1.79) Luzon (1.34) (1.34) (1.53) (1.71) VI (0.88) (0.82) (0.97) (0.99) VII (1.00) (1.01) (1.19) (1.18) VIII (1.21) (1.08) (3.88) (1.61) Visayas (1.01) (0.96) (1.23) (1.18) IX (1.12) (1.37) (1.14) (1.26) X (1.14) (1.41) (1.39) (1.51) XI (0.93) (1.00) (1.13) (1.13) XII (0.66) (0.87) (1.14) (0.89) ARMM (1.00) (0.85) (0.70) Final Report Page 99

121 Residential Low voltage Commercial Low voltage Industrial High voltage Industrial CARAGA (0.99) (1.49) (0.60) (1.32) Mindanao (1.19) (1.11) (1.16) (1.25) All regions (1.28) (1.31) (1.42) (1.56) 3.2 All subsidies One of the objectives of EPIRA is to remove the web of subsidies that prevent prices from reflecting the true costs of providing electricity services. This objective has been fairly met and partly accounts for the rise in electricity prices as was noted in Section II. There are only two remaining subsidies that are considered permanent to the extent that there is no time frame as to when they would be eliminated. These are the lifeline and senior citizens discounts. Eliminating these two remaining subsidies from the base composite price generates the prices in the next Table. Table VI.13 Base Composite Prices After Eliminating All Subsidies (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 1, , , Luzon 1, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , The reduction in prices caused by removing all subsidies varies across DUs and ranges from 0.6% to 3.89%. The changes, shown below, are however not very different from those that result in removing lifeline discounts. Overall composite residential tariff is reduced by 1.29%, instead of 1.28% when only lifeline discounts are eliminated. For other customer classes, the changes in overall tariffs are nil, hence they do not show up in the next table. Final Report Page 100

122 Table VI.14 Impact on Base Composite Price of Eliminating All Subsidies (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR (1.47) (1.40) (1.57) (1.81) CAR (0.92) (1.00) (0.97) (1.48) I (0.94) (1.06) (1.28) (1.29) II (0.90) (0.96) (1.19) (1.17) III (0.74) (0.72) (1.09) (0.88) IVA (0.78) (0.85) (1.08) (0.89) IVB (0.88) (1.03) (1.03) V (1.17) (1.29) (2.09) (1.80) Luzon (1.35) (1.34) (1.54) (1.71) VI (0.89) (0.82) (0.97) (0.99) VII (1.00) (1.01) (1.19) (1.18) VIII (1.22) (1.08) (3.89) (1.62) Visayas (1.01) (0.97) (1.24) (1.18) IX (1.13) (1.37) (1.15) (1.26) X (1.15) (1.42) (1.39) (1.51) XI (0.93) (1.00) (1.13) (1.13) XII (0.67) (0.88) (1.14) (0.90) ARMM (1.00) (0.85) (0.70) CARAGA (0.99) (1.50) (0.60) (1.33) Mindanao (1.20) (1.12) (1.16) (1.25) All regions (1.29) (1.31) (1.42) (1.56) 4. Pricing of Indigenous Fuels EPIRA stipulates that a universal charge may be levied on all electricity users to equalize the taxes and royalties applied to indigenous or renewable sources of energy vis-à-vis imported energy fuels 52. Taking off from this provision, several proposals have been advanced to lower the royalties collected on indigenous fuels so as to meet the objective of the reform that of removing the discriminatory tax on renewables in order to promote their use and consequently reduce the country s dependence on imported energy. For instance, the Explanatory Note to Senate Bill No. 2, titled An Act Directing the Reduction of Electricity Rates through the Utilization of the Government Share in the Discovery, Exploration, Development and/or Production of Indigenous Sources of Energy for the Purpose of Lowering the Cost of Electricity reads: (M)uch is left to be desired with respect to other indigenous sources of energy. Government impositions associated with making available such resources for electricity generation are more burdensome than those applied on imported fuels such that rates of electricity generated using indigenous energy resources are rendered artificially high. For instance, as of May 2007, government royalties (or government share) on indigenous natural gas was around P1.46/kWh, which was 5 to 8 times more than the taxes imposed on imported fuels such as coal (P0.l7/kWh), oil (P0.20/kWh) and liquefied natural gas (P0.29/kWh). If taxes and royalties were to be removed on both indigenous and imported fuels, the rates of electricity generated using indigenous energy resources would be substantially lower. Moreover, between indigenous petroleum which is intensively used for generating electricity and other local extractive industries such as mining, the former is being subjected to royalties of about 60% while the latter enjoys a much lower tax rate of 3%. 52 RA 9136, Section 34(c). Final Report Page 101

123 In principle, royalties on indigenous fuels are compensation for the use of natural resource, hence it should be considered part of the cost of harnessing the natural resource into fuel. Import duties, on the other hand, are government assessments upon the value of imports, hence it is not an intrinsic cost of the latter. It follows that royalties on natural gas cannot be compared to tariffs on imported fuels such as coal and LNG, since they serve different purposes. The former is an economic cost, whereas the latter is a tax. Thus differences between royalties on indigenous fuels and taxes on imported fuels cannot be a basis of a conclusion that one form of fuel is discriminated over another. Nonetheless, this section explores several scenarios of utilizing royalties income to lower electricity tariffs. As in the other simulations, the objective is merely to estimate the potential impact on tariffs without rendering conclusion on the appropriateness of the policy measure. It should also be considered that the royalty incomes are fluctuating, hence the impact on electricity tariffs depend on when it is reckoned. Table VI.15 Royalties on Natural Gas and Geothermal Royalties (Php million) Natural Gas 5,370 8,229 25,499 37,458 19,765 29,928 Geothermal ,171 1, Electricity Generation (GWh) Natural Gas 16,366 18,789 19,576 19,887 19,518 20,591 Geothermal 9,939 8,563 9,843 9,788 9,929 9,942 Royalties per kwh (Php/kWh) Natural Gas Geothermal Source: Department of Budget and Management for royalties income; Department of Energy for electricity generation. 4.1 Geothermals The Philippines is reputed to be one of largest producers of geothermal power in the world. In 2011, 9,942 Gwh of geothermal power was produced, representing 14% of total electricity generation during the period. Of this, 35% is generated in Luzon, 56% in Visayas, and the rest in Mindanao. The total geothermal energy contracted forward in 2011 was 1,778 GWh or 18% of actual generation. These are covered in 17 bilateral contracts between DUs and two generation companies, AP Renewables Inc. (APRI) and Green Core Geothermal Inc. (GCGI), as summarized below. Table VI.16 Bilateral Contracts on Geothermal Electric Power Contracted Energy 2011(MWh) Basic Energy Charge (P/kWh) WACC (%) Price Index Generation Company % of Sales CASURECO IV APRI 35, NCPI; CPI ALECO APRI 129, NCPI; CPI ILECO I GCGI 26, CPI CAPELCO GCGI 105, CPI AKELCO GCGI 87, CPI NORECO II GCGI 17, CPI VECO GCGI 525, CPI ILECO II GCGI 17, CPI Final Report Page 102

124 Contracted Energy 2011(MWh) Basic Energy Charge (P/kWh) WACC (%) Price Index Generation Company % of Sales NORECO I GCGI 17, CPI VRESCO GCGI 61, CPI NOCECO GCGI 35, CPI LEYECO V GCGI 52, CPI LEYECO II GCGI 96, CPI DORELCO GCGI 26, CPI SORECO I APRI 29, NCPI; CPI SFELAPCO APRI 35, NCPI; CPI BELS* APRI 129, NCPI; CPI Note: The contracting party is First Bay Power Corporation which has taken over the rehabilitation of BELS (Bauan Electric Lights System) Electric Distribution Utility. Contracted prices are escalated or deescalated based on the movements of Newcastle Coal Price Index (NCPI) and Consumer Price Index (CPI) or CPI only. Most (i.e., 12 of 17 contracts) stipulate CPI only. Where price is adjusted based on CPI only, the generation utility (in this case, GCGI) absorbs the risk of changes in the cost of geothermal steam which in turn is indexed to global coal prices and foreign exchange. The allowable capital recovery charge, which is included in the basic energy charge, is computed based on 14.3 to 16.7 percent weighted average cost of capital (WACC). As part of the Renewable Energy Act, the Philippine government is providing a package of incentives to investors in steam field development and electricity generation using geothermal sources. The package consists of fiscal incentives, enumerated in Table II.32, and non-fiscal incentives that include Renewable Portfolio Standard (requiring electricity service providers to source a certain proportion of their energy supply from geothermal sources), priority connection to the grid, and priority purchase and transmission by grid system operators. Nonetheless, as geothermal energy is considered a mineral resource, the government collects royalty equivalent to 1.5% of gross income from sale of geothermal steam and sale of electricity generated from geothermal energy. Although geothermal power is priced lower than other sources of electricity, the basic energy charge stipulated in the bilateral contracts, averaging P4.6442/kWh or US cents/kwh, is still perceived high by some quarters, since it exceeds prices of geothermal power in other countries. For example, PLN of Indonesia pays 9.7 US cents per kwh to IPPs supplying geothermal power. A comparison with Indonesia is perhaps inappropriate for a number of reasons. Foremost, Indonesia has the largest estimated geothermal resource in the world and is the world s third largest producer of geothermal power. In June 2012 the Indonesian government announced plans to expand its current 1,200 MW of geothermal capacity by about 4,000 to 5,000 MW. The estimated geothermal resource in the Philippines is only one-third of Indonesia s. More importantly, electricity prices in Indonesia are heavily subsidized. Indonesia s 2013 state budget includes an electricity subsidy of 78.6 trillion rupiah (US$8.3 billion). In addition, the Indonesian government does not collect royalty in the extracted steam nor in the generated power, unlike the Philippines. Thus, it is difficult to use any Indonesian price related to electricity service as benchmark since it is likely to be below cost. Indeed, there have been indications that the price of geothermal power in Indonesia may be raised to between 10 and 17 US cents per kwh. Still, there are suggestions to lower Philippine electricity tariffs using royalties collected from indigenous fuels. Two scenarios are simulated in the case of geothermal royalties. The first is a uniform rebate of geothermal royalties, with total royalties allocated proportionately to Final Report Page 103

125 the major islands based on their shares in total electricity generated from geothermal resource. Another scenario is to allocate royalties first to DUs with forward contracts on geothermal, then to all other customers. The rebate to DUs with forward contracts is proportionate to their contracted energy. Both cases preserve the incentive to use geothermal (unlike removing or reducing VAT) since customers of DUs that chose to use geothermal power are benefitted more by the rebate than customers of other DUs. In the first case, the estimated rebate per customer can be traced from the next Table. The total geothermal royalty in 2011, P492 million, is allocated to the major islands proportionately based on their contributions to total electricity generated from geothermal. Within a major island, however, a uniform rebate is applied. The largest rebate accrues to consumers in Visayas since they contribute the most to geothermal production. Consumers in Mindanao receive a larger rebate than consumers in Luzon even as the share of Mindanao in generation is smaller since the amount is allocated to a smaller number of consumption. Table VI.17 Computation of Proportionate Rebate Using Royalties on Geothermal Luzon Visayas Mindanao Total Net consumption* (GWh) 41,706 7,224 7,167 56,098 Generation of geothermal (GWh) 3,486 5, ,942 Share of royalties (%) Royalties distributed to consumers (P 000) 172, ,084 41, ,346 Rebate per kwh** *Consumption less system loss and own-use **Share of royalties divided by net consumption The next table presents the base composite prices after adjusting for rebates. Consumers in Visayas enjoy the largest reduction in rates, which increases with consumption. Thus, the average residential tariffs in Visayas are reduced by P7.70; commercial tariffs by P115.50; low voltage industrial tariffs by P1,925; and high voltage industrial tariffs by P7,700. By comparison, the changes in tariffs in Luzon are much more modest at P0.82, P12.30, P205, and P820 for residential, commercial, low voltage industrial and high voltage industrial tariffs, respectively. Table VI.18 Base Composite Prices with Proportionate Rebate of Geothermal Royalties (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 1, , , Luzon 2, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , Final Report Page 104

126 Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , Although the tariff reductions in Visayas seem significant in total value, the largest cuts (Region VIII) are just about one-half of one percent when expressed as proportion of monthly bill. On average, the reduction in all customer classes is merely a tenth of one percent. Table VI.19 Impact on Base Composite Prices of Proportionate Rebate of Geothermal Royalties (in percent) Residential Low voltage Commercial Low voltage Industrial High voltage Industrial NCR (0.04) (0.04) (0.04) (0.05) CAR (0.04) (0.05) (0.04) (0.05) I (0.04) (0.05) (0.05) (0.05) II (0.04) (0.05) (0.04) (0.04) III (0.04) (0.05) (0.05) (0.05) IVA (0.04) (0.05) (0.05) (0.05) IVB (0.04) (0.04) (0.04) V (0.04) (0.05) (0.05) (0.05) Luzon (0.04) (0.04) (0.04) (0.05) VI (0.37) (0.43) (0.39) (0.40) VII (0.40) (0.43) (0.44) (0.44) VIII (0.44) (0.51) (0.52) (0.54) Visayas (0.40) (0.44) (0.44) (0.44) IX (0.09) (0.10) (0.09) (0.09) X (0.07) (0.09) (0.09) (0.09) XI (0.08) (0.08) (0.09) (0.09) XII (0.09) (0.10) (0.10) (0.11) ARMM (0.10) (0.09) (0.07) CARAGA (0.08) (0.10) (0.10) (0.10) Mindanao (0.08) (0.09) (0.09) (0.09) All regions (0.08) (0.06) (0.15) (0.13) An alternative allocation of royalties is to set aside the share of DUs with bilateral contracts on geothermal power before distributing the remaining royalties to all other DUs. Thus, since the total contracted energy represents 18% of total electricity generated from geothermal sources, P88 million (18% of P492 million) is reserved to DUs with forward geothermal contracts. This amount is distributed to the 17 DUs in proportion to the energy they have contracted. The remaining royalties, P404 million, is distributed in the same way as in the previous case (Table VI.17). The rebates per kwh amount to P0.0034, P and P for Luzon, Visayas and Mindanao customers. In addition, customers of DUs with forward contracts receive rebates for the contracted energy as shown below. Thus, customers of CASURECO IV receive a total rebate of P per kwh, i.e., uniform rebate for Luzon customers of P per kwh plus additional rebate for contracted energy of P per kwh. Final Report Page 105

127 Table VI.20 Computation of Additional Rebates to DUs with Forward Geothermal Contracts Distribution Utility Contracted Energy (MWh) Allocated Royalties (P 000) Energy Sales (MWh) Add l Rebate (P/kWh) CASURECO IV 35,688 1, , ALECO 129,714 6, , ILECO I 26,280 1, , CAPELCO 105,120 5, , AKELCO 87,600 4, , NORECO II 17, , VECO 525,600 26, ,354, ILECO II 17, , NORECO I 17, , VRESCO 61,320 3, NOCECO 35,040 1, , LEYECO V 52,560 2, , LEYECO II 96,360 4, , DORELCO 26,280 1, SORECO I 29,530 1, , SFELAPCO 477,303 23, , BELS* 37,084 1, The composite prices after adjusting for these rebates are presented below. These prices are slightly higher than those presented in Table VI.18 since the uniform rebates are smaller (e.g., P instead of P for Luzon customers) although some DUs have double rebates. Table VI.21 Base Composite Prices with Additional Rebates to DUs with Forward Geothermal Contracts (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , V 1, , , Luzon 2, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , CARAGA 1, , , Mindanao 1, , , All regions 1, , , Accordingly, the proportional changes in regional composite prices are smaller in this alternative scenario because of smaller rebates to most DUs, and since the DUs with Final Report Page 106

128 forward geothermal contracts are generally smaller than other DUs (except VECO) belonging to the same region. Since most DUs with forward contracts are in Region VIII, customers in this region have the largest tariff reduction but only by as much as threefourths of one percent. Table VI.22 Impact on Base Composite Prices of Additional Rebate of Geothermal Royalties to DUs with Forward Geothermal Contracts (in percent) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR (0.03) (0.03) (0.04) (0.04) CAR (0.03) (0.04) (0.04) (0.04) I (0.03) (0.04) (0.04) (0.04) II (0.03) (0.04) (0.04) (0.03) III (0.10) (0.13) (0.30) (0.20) IVA (0.04) (0.04) (0.04) (0.04) IVB (0.03) (0.04) (0.04) V (0.14) (0.14) (0.28) (0.25) Luzon (0.04) (0.04) (0.05) (0.05) VI (0.38) (0.48) (0.33) (0.35) VII (0.40) (0.43) (0.45) (0.45) VIII (0.45) (0.55) (0.64) (0.72) Visayas (0.40) (0.46) (0.44) (0.45) IX (0.07) (0.09) (0.08) (0.08) X (0.06) (0.07) (0.07) (0.07) XI (0.07) (0.07) (0.07) (0.08) XII (0.07) (0.08) (0.08) (0.09) ARMM (0.08) (0.07) (0.06) CARAGA (0.07) (0.08) (0.08) (0.08) Mindanao (0.07) (0.07) (0.07) (0.08) All regions (0.08) (0.06) (0.15) (0.13) 4.2 Natural Gas With nearly 30% of electricity generated from natural gas and generation component accounting from more than half of tariffs, there are bound to be proposals to lower tariffs involving the pricing of natural gas. Except for Singapore, all countries included in this study are producers of natural gas. Indonesia and Malaysia are, however, net exporters, while Thailand is a net importer, and the Philippines neither exports nor imports natural gas. The statistics on production, consumption, exports and imports of natural gas for the five ASEAN countries are given in the table below. Table VI.23 Natural Gas Production, Consumption and Trade in Selected ASEAN Countries (in billion cubic meters) Countries Production Consumption Imports Exports Indonesia Malaysia Philippines Singapore Thailand Source: CIA, The World Factbook, at: (accessed 15 October 2012) Final Report Page 107

129 Note: Data is for 2010 (estimated). A significant indigenous source of primary energy in the Philippines is the Malampaya gas field that provides natural gas to fuel three combined cycle gas turbine (CCGT) power plants with a combined capacity of 2,760 MW and generating about 40% of Luzon s power requirement. The natural gas-fueled power plants are the 560-MW San Lorenzo, 1,000-MW Sta. Rita, and the 1,200-MW KEPCO-Ilijan. San Lorenzo and Sta. Rita generation plants are owned by First Gas. In 2011, the average daily production of natural gas was 70,000 barrels of oil equivalent. 53 About three-fifths of MERALCO s power supply comes from natural gas sourced from Malampaya. For the first three quarters of 2011, MERALCO s generation cost of electricity using natural gas was in the range of P4.65 to P4.76 per kwh. In line with the country s policy to promote the development, production and utilization of the country s indigenous energy resources, the Department of Energy granted service contracts for the exploration and development of indigenous petroleum. The incentives given to service contractors are provided for in the Oil Exploration and Development Act of 1972 (Presidential Decree 87), enumerated in Table II.31. Under a service contract, the private sector contractor provides the service and technology for which it is paid a service fee. The government retains ownership of all petroleum produced. Given this, the government should provide financing to the contractor. If it cannot, the proceeds from the sale of the petroleum become the source of funds for the service fee and operating expenses of the contractor. There is no explicit royalty, but the contract is structured as a production sharing arrangement where the gross proceeds less maximum allowable operating expenses (also called net proceeds) is divided between the government and contractor on a 60:40 basis in favor of the former. The maximum allowed cost recovery is 70% of gross proceeds. As a result, the implicit royalty that can be considered mineral payments to the government is at least 18% of gross income, assuming no foreign participation, or 13.5 % of gross income if the project qualifies for the maximum Filipino Participation Incentive Allowance (FPIA). 54 The Malampaya project is not availing of the FPIA incentive. At the start of the commercial operations of the Malampaya gas field in 2001, the Shell consortium had invested US$2.1 billion. By 2006, the consortium had recovered its capital investment. The consortium utilized the maximum cost reimbursement of 70% of gross production from 2001 to 2005, but only 27% in 2006 and 17% in By 2011, the cost reimbursement was reduced to 10% of gross production, hence the net proceeds was 90% of gross production, which was split between the government and Shell consortium on a 60:40 basis. Thus, the government s share in 2011 was therefore 54%, which however includes all taxes due to the contractor. The price of the Malampaya gas is set in the 25-year long-term contract between the government and the Malampaya Shell consortium. The pricing formula is based on some base price that changes over the years as specified in the contract and adjusted by the US CPI, and the Oman, Dubai and Mean of Platts (MOPs) oil price indices. The Philippine price resulting from this formula for natural gas is said to be higher than those in Japan and the US. Two sets of bills pertaining to the natural gas industry are currently pending in Congress. One set is for the development of the downstream natural gas industry; another is for the 53 Sunley, et al. (2012). 54 See Table II.31. Final Report Page 108

130 reduction of electricity rates using government share in the production of natural gas. In the latter, the proposal is to reduce government share effectively to 3% of net proceeds from the sale of the energy resource over the life of the service contract. The bill mandates the ERC to determine the reduction in electricity rates of each customer class, but priority should be given to efficient end-users such as industrial loads for maximum multiplier effect on the national economy and to marginal end-users for more meaningful benefits. Unlike geothermal resource where there are generation plants in all three major islands running on the resource, usage of natural gas is geographically confined in Luzon, and much of the capacity of natural gas-fuelled generation plants are tied to bilateral contracts with MERALCO. It is therefore logical to simulate the impact of returning royalty incomes to electricity customers as rebate under the following scenarios: (i) all rebates accrue to MERALCO consumers; (ii) rebates are distributed uniformly to Luzon customers; and (iii) rebates are allocated only to industrial customers nationwide. The 2011 royalty income on natural gas was P29.9 billion, representing 54% of net proceeds. If the government were to retain 3% of net proceeds based on the provision of the proposed bill, P28.3 billion is available for rebates that may be distributed as follows: Table VI.24 Possible Distribution of Electricity Rebates Using 2011 Natural Gas Royalty MERALCO customers Luzon customers Industrial customers Uniform to all Electricity consumption (GWh) 29,805 41,706 19,334 56,098 Rebate (Php per kwh) The regional composite prices after adjusting for rebates from royalty income on natural gas under each of the three scenarios are shown in Table VI.25. The corresponding changes in the base composite prices are juxtaposed in Table VI.26. Final Report Page 109

131 Table VI.25 Base Composite Prices with Rebates from Natural Gas Royalties (in Philippine peso) Residential Commercial Region Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case 4 NCR 1, , , , , , , , CAR 2, , , , , , , , I 1, , , , , , , , II 1, , , , , , , , III 1, , , , , , , , IVA 1, , , , , , , , IVB 2, , , , , , , , V 1, , , , , , , , Luzon 1, , , , , , , , VI 2, , , , , , , , VII 1, , , , , , , , VIII 1, , , , , , , , Visayas 1, , , , , , , , IX 1, , , , , , , , X 1, , , , , , , , XI 1, , , , , , , , XII 1, , , , , , , , ARMM 1, , , , , , , , CARAGA 1, , , , , , , , Mindanao 1, , , , , , , , All regions 1, , , , , , , , Note: Case 1 refers to rebates to MERALCO customers only; case 2, to Luzon customers only; case 3, to industrial customers only; case 4, to all customers. Final Report Page 110

132 Table VI.25 Base Composite Prices with Rebates from Natural Gas Royalties, continued (in thousand Philippine peso) Low Voltage Industrial High Voltage Industrial Region Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case 4 NCR , , , , CAR , , , , I , , , , II , , , , III , , , , IVA , , , , IVB V , , , , Luzon , , , , VI , , , , VII , , , , VIII , , , , Visayas , , , , IX , , , X , , , , XI , , XII , , , ARMM CARAGA , , , Mindanao , , , All regions , , , , Note: Case 1 refers to rebates to MERALCO customers only; case 2, to Luzon customers only; case 3, to industrial customers only; case 4, to all customers. Final Report Page 111

133 Table VI.26 Impact on Base Composite Prices of Rebates from Natural Gas Royalties (in percent) Residential Commercial Region Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case 4 NCR (9.24) (6.60) (5.20) (8.78) (6.27) (4.94) CAR - (6.64) (5.23) - (8.15) (6.41) I - (6.91) (5.44) - (7.87) (6.20) II - (6.95) (5.47) - (8.12) (6.39) III - (7.14) (5.62) - (7.70) (6.06) IVA - (7.20) (5.67) - (8.37) (6.59) IVB - (6.12) (4.82) - (7.16) (5.64) V - (6.81) (5.36) - (7.81) (6.15) Luzon (7.36) (6.69) (5.26) (7.82) (6.44) (5.07) VI - - (5.17) - - (5.94) VII - - (5.58) - - (6.00) VIII - - (6.09) - - (7.10) Visayas - - (5.57) - - (6.13) IX - - (8.17) - - (9.50) X - - (6.37) - - (8.31) XI - - (7.29) - - (7.46) XII - - (7.83) - - (8.74) ARMM - - (9.20) - - (7.86) CARAGA - - (7.57) - - (9.18) Mindanao - - (7.29) - - (8.10) All regions (6.02) (5.47) (5.46) (6.98) (5.75) (5.29) Note: Case 1 refers to rebates to MERALCO customers only; case 2, to Luzon customers only; case 3, to industrial customers only; case 4, to all customers. Final Report Page 112

134 Table VI.26 Impact on Base Composite Prices of Rebates from Natural Gas Royalties, continued (in percent) Low Voltage Industrial High Voltage Industrial Region Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case 4 NCR (9.79) (7.00) (15.09) (5.51) (11.33) (8.10) (17.46) (6.37) CAR - (7.05) (15.20) (5.55) - (7.53) (16.24) (5.92) I - (7.44) (16.05) (5.86) - (7.73) (16.67) (6.08) II - (7.19) (15.52) (5.66) - (6.52) (14.07) (5.14) III - (8.36) (18.04) (6.58) - (8.96) (19.32) (7.05) IVA - (8.01) (17.28) (6.30) - (8.49) (18.31) (6.68) IVB - (7.13) (15.38) (5.61) V - (8.32) (17.95) (6.55) - (8.18) (17.65) (6.44) Luzon (8.84) (7.10) (15.31) (5.59) (10.03) (8.14) (17.56) (6.41) VI - - (14.75) (5.38) - - (15.28) (5.58) VII - - (16.78) (6.12) - - (16.89) (6.16) VIII - - (19.85) (7.24) - - (20.41) (7.45) Visayas - - (16.66) (6.08) - - (16.88) (8.65) IX - - (23.49) (8.57) - - (23.71) (6.16) X - - (21.80) (7.96) - - (22.08) (8.55) XI - - (21.73) (7.93) - - (23.44) (10.29) XII - - (25.43) (9.28) - - (28.18) (9.25) ARMM - - (17.76) (6.48) CARAGA - - (25.27) (9.22) - - (25.35) (8.62) Mindanao - - (22.33) (8.15) - - (23.62) (6.61) All regions (5.69) (4.57) (16.37) (5.97) (7.07) (5.73) (18.10) (6.37) Note: Case 1 refers to rebates to MERALCO customers only; case 2, to Luzon customers only; case 3, to industrial customers only; case 4, to all customers. Final Report Page 113

135 The following observations proceed from the last two tables: (i) Even when the rebates are exclusive to MERALCO customers, the national composite prices for all customer classes will decline significantly because of the weight attached to MERALCO. (ii) As expected, the changes in national composite prices are smaller when the rebates are spread to all Luzon customers (Case 2) compared to when they are afforded only to MERALCO customers (Case 1). Hence, residential tariffs decline by 6% in Case 1 against 5.5% in Case 2. Similarly, high voltage industrial tariffs will fall by 7.1% in Case 1 but only by 5.7% in Case 2. This again reflects the weight attached to MERALCO tariffs in the national composite prices, such that when the rebates to MERALCO customers are smaller, national composite prices decline also by a smaller proportion. (iii) Focusing the rebates on industrial customers, i.e., Case 3, will produce the largest tariff changes for the affected consumers. Thus, industrial customers connected to low and high voltage wires, respectively, will receive 16% and 18% discounts, respectively, on their monthly bills. Residential and commercial tariffs are of course unperturbed under this scenario. (iv) A uniform rebate to all customers will reduce base composite prices by 5 to 6 percent depending on customer class. As this affects the largest number of customers, the discount per customer is accordingly the smallest among the four scenarios. 5. Changing the Basis of Regulation on Distribution 5.1 Performance-based Regulation for ECs Until recently, ECs have been treated differently by ERC in terms of rate setting. Whereas PIOUs are allowed to realize reasonable returns on their capital assets, tariffs for ECs are set under a cash flow regulatory regime. This means that the rate allows the ECs to generate revenues sufficient to cover payroll, operations and maintenance outlays, debt service including interest and allowance strictly for reinvestment purposes. 55 Pursuant to EPIRA giving ERC the leeway to determine the appropriate rate-setting methodology that would ensure a reasonable price of electricity, the regulator has issued in 2009 the Rules for Setting the Electric Cooperatives Wheeling Rates (RSEC-WR). The new framework is a form of performance-based regulation (PBR) akin to the framework adopted for PIOUs, but takes into account the distinctive characteristics of ECs. It rewards efficiency, which therefore requires monitoring of performance. However since there are six times more ECs than PIOUs, it is necessary to establish a methodology that is easy for ERC to monitor compliance. Thus the new regulatory framework has the following key features. First, ECs are classified into seven groups based on their operating distribution costs which were found to be highly correlated to the number of customers and customer consumption. Second, the regulator determines an initial tariff and a tariff glide path for each EC group that would serve as rate caps for a regulatory period. Third, the tariff glide path allows for tariff adjustment during the regulatory period based on an escalation factor to reflect current costs, efficiency factor and performance incentive index. Fourth, a uniform customer classification based on the power 55 RSEC-WR, p.2. Final Report Page 114

136 voltage used in delivering service to customers is imposed to simplify the allocation of costs consistent with cost of service delivery. Finally, a transition period is allowed from the current to the new tariff regulatory structure. During 2011, 32 ECs have already transitioned to the new regulatory regime. All other ECs are expected to complete their transition by Table VI.27 Regulatory Classification of Electric Cooperatives No. of Customers ( 000) Mean Consumption (kwh/customer) Grp No. of ECs Consumption (MWh per yr) Electric Cooperatives A 11 < AURELCO, BILECO, CAMIGUIN, GUIMELCO, IFELCO, KAELCO, MOPRECO, QUEZELCO II, QUIRELCO, SIARELCO B 16 < ABRECO, ANTECO, CASURECO I, CASURECO IV, LANECO, LEYECO I/DORELCO, LEYECO IV, MOELCI I, ESAMELCO, NORSAMELCO, SAMELCO I, SAMELCO II, SORECO I, SOLECO, SURSECO I, SURSECO II C 6 < BOHECO II, CAGELCO II, CASURECO III, ISELCO II, SORECO II D ASELCO, BUSECO, CEBECO III, DORECO, FLECO, ILECO III, MAGELCO, MOELCI II, MORESCO II, NORECO I, NUVELCO, PRESCO, PANELCO I, SUKELCO, SURNECO, ZAMECO I, ZAMECO II E AKELCO, BOHECO I, FIBECO, CAGELCO I, CONORECO, CAPELCO, CEBECO I, CEBECO II, DASURECO, ILECO I, ILECO II, LUELCO, LEYECO V, NOCECO, NORECO II, COTELCO, NEECO I, NEECO II Area I, NEECO II, Area II, PELCO I, PANELCO III, QUEZELCO I, TARELCO I, TARELCO II, VRESCO, ZANECO, ZAMSURECO I, SAMSURECO II F ANECO, ALECO, BATELEC 1, BENECO, CASURECO II, CENPELCO, DANECO, INEC, ISECO, ISELCO I, MORESCO I, PELCO II, PENELCO, SAJELCO, SOCOTECO I G BATELEC II, CENECO, LEYECO II, PELCO III, SOCOTECO II, ZAMCELCO Source: RSEC-WR. Two ECs in the above list, namely QUEZELCO II (Group A) and ANTECO (Group B), are members of the Association of Isolated Electric Cooperatives (AIEC), i.e., they service missionary areas and are supplied by NPC-SPUG. But AIEC has 37 other members not included in this list. Among those excluded in this transition order that are among the DUs covered in this study are BATANELCO, CELCO, DIELCO, FICELCO, LASURECO, LUBELCO, MARELCO, MASELCO, OMECO, ORMECO, PROSIELCO and TIELCO. Had all the ECs completed their transition at the beginning of 2012, the base composite prices would have been as presented below. Final Report Page 115

137 Table VI.28 Base Composite Prices Post-Completion of ECs Transition to PBR (in Philippine peso) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR 2, , , CAR 2, , , I 1, , , II 1, , , III 1, , , IVA 1, , , IVB 2, , , V 2, , , Luzon 2, , , VI 2, , , VII 1, , , VIII 1, , , Visayas 1, , , IX 1, , , X 1, , , XI 1, , , XII 1, , , ARMM 1, , , CARAGA 1, , , Mindanao 1, , , All regions 1, , , The changes in tariffs resulting from this new regulatory regime are uneven among ECs and customer classes. This can be inferred from the next Table which shows the number of ECs whose tariffs will change when the transition is completed and the average changes in tariffs within each EC group and customer class. There are more ECs whose tariffs will decrease than increase. Residential customers of SORECO I (Sorsogon) will experience the largest increase in their tariffs by 42.9%, while the tariffs of industrial customers connected to low voltage wires of CEBECO III will contract the most by 8.8%. Group B s tariffs will generally go up, whereas Group F s will fall for all customer classes. For most ECs and EC groups, however, the tariff changes will be mixed depending on customer class. Table VI.29 Changes in Composite Prices of Post Completion of Transition to PBR (in percent unless otherwise specified) Residential LV Commercial LV Industrial HV Industrial ECs that completed their transition in ECs whose tariffs will increase after transition ECs whose tariffs will decrease after transition Maximum increase Maximum decrease Percent change in tariffs of: Group A (1.01) 0.23 (0.88) 7.26 Final Report Page 116

138 Residential LV Commercial LV Industrial HV Industrial Group B Group C (2.62) 0.95 (2.98) (0.34) Group D 0.26 (0.32) (0.54) (0.78) Group E (0.64) (0.16) Group F (0.22) (0.44) (0.05) (0.51) Group G (1.75) (0.06) (1.41) 0.03 In terms of regional composite prices, the changes appear less significant. Shown in the next table are less than 1 percent changes in tariffs for most regions and customer classes, caused by the fact that the ECs shares in electricity sales are generally smaller compared to PIOUs belonging to the same region. In all, residential and high voltage industrial tariffs will fall, while commercial and low voltage industrial tariffs will rise once the transition into the new regulatory regime is completed. Table VI.30 Impact on Base Composite Prices of Post-Completion of ECs Transition to PBR (in percent) Residential Low voltage Commercial Low voltage Industrial ( 000) High voltage Industrial ( 000) NCR CAR I (0.31) (0.07) (0.02) (0.17) II (0.16) 0.20 (1.13) (2.15) III (0.28) (0.02) (0.24) (0.09) IVA (2.30) (0.10) IVB V (0.08) - Luzon (0.08) 0.00 (0.02) 0.02 VI (0.51) VII (0.00) (0.01) VII (1.09) (3.39) Visayas (0.32) (0.14) IX (0.28) (0.02) X 0.49 (0.15) (0.07) (0.05) XI (0.04) (0.15) 0.07 (0.27) XII (0.99) ARMM (0.09) CARAGA - (0.07) (0.02) 0.05 Mindanao (0.31) (0.12) All regions (0.11) (0.02) Final Report Page 117

139 5.2 Asset Revaluation for Computation of Revenue Caps on PIOUs PIOUs, like ECs, transitioned to the new regulatory regime which rewards good performance and penalizes below standard quality of services. The transition occurred in phases, with the first group, consisting of MERALCO, DECORP and CEPALCO, being subjected to the new regime in mid-2007; the fourth and last group, in the last quarter of A uniform methodology is applied in setting the rates for all PIOUs, as detailed in the Rules for Setting Distribution Wheeling Rates for Privately Owned Distribution Utilities entering Performance Based Regulation (RDWR). But since the entry into PBR occurred in different dates, the critical variables such as weighted average cost of capital (WACC) and working capital factor (WCF), which determine the allowed return on capital and consequently revenue caps, differ for each group. Thus the first group has the lowest WACC, 12.8%, while the second group which entered into PBR two years after the first, the highest, at 16.27%. The most recent entrants are allowed 14.97% return. Table VI.31 Dates of Entry of PIOUs to PBR and Applicable WACC and WCF during the First Regulatory Period Group Distribution Utility First Regulatory Period WACC(%) WCF (%) A MERALCO, DECORP, 1 Jul Jun CEPALCO B CLPC, ILPI, MECO 1 Apr Mar C CELCOR, LUELCO, TEI, 1 Jul Jun VECO, IEEC, DLPC D AEC, SZ, CEDC, SFELAPCO, PECO, BLCI 1 Oct Sep The rates are set by estimating the revenue (referred to as annual revenue requirement or ARR) needed by a DU to cover its forecast operating expenses, wear and tear of assets (depreciation), taxes (including corporate income, if applicable), and return on capital. The DU then determines the rate that would apply to the different customer classes so it could generate revenues that could not exceed the ARR. A price cap is also computed by the regulator by applying the forecast energy sales on the ARR. The rates are adjusted annually during the regulatory period for inflation (using consumer price index, CPI) and DU s performance that is assessed against a set of service level standards imposed by the regulator. If as a result of the rates set, the DU s revenues exceed or fall short of the ARRs, the rates may be adjusted in the next year to take account of the over- or under recovery. Even before the adoption of PBR, rate setting approaches for ECs and PIOUs were already different in that the latter were allowed returns on their capital investment. Consequently, all else equal, PIOU rates are higher than ECs. And yet this gap widens even more under RDWR as the assets of PIOUs are revalued to replacement cost for purposes of computing the regulatory asset base (RAB) and allowed return on capital. Previous regulatory regime that controlled the DU s price according to a prescribed ceiling on rate of return used the historical cost of the asset base instead. Replacement cost or fair market value are usually higher than historical cost, but can also be lower due to technological change. Yet the higher the RAB, the higher the revenue cap, and hence the higher the regulated distribution charge. On the other hand, the RDWR also adopted the so called optimized depreciated replacement cost (ODRC) to ensure that only prudent investments are included in the RAB. This means that not all assets in the DU s books are included in the RAB; those that are not considered Final Report Page 118

140 relevant for efficient distribution of electricity services are optimized out. And yet despite optimization, using ODRC on MERALCO nearly doubles the utility s asset base as can be gleaned below. Table VI.32 Revaluation of MERALCO s Assets for Regulatory Period July 2007 June 2011 Value (in Philippine peso) Percent Book value of assets as of 30 June ,619,313, Replacement cost 168,234,763, Optimized replacement cost 154,420,577, Optimized depreciated replacement cost 96,351,659, Source: Regulatory Reset for Manila Electric Corporation, July 2007 to June 2011, Final Determination, p. 51; Regulatory Asset Base Valuation using ODRC: MERALCO Experience, available at for historical cost data. Thus, the starting value for the computation of RAB is twice the historical cost (book value) of assets. Since the allowed return on capital necessarily depends on the size of the asset on which the regulated rate of return is applied, the regulatory approach of revaluing assets by its replacement cost has been criticized albeit being adopted by a number of regulators including Australia and New Zealand. The key criticism hinges on the revaluation of assets of the regulated firm at replacement cost. While it is recognized that the objective of asset revaluation is to set the rate base that would support capital investments necessary for efficient production (or delivery of services), the contention is that the application of replacement cost should not have extended to assets that are already sunk because it does not create additional incentive for future capital investments. It is argued that enticing a regulated firm to commit capital to a network utility requires only an assurance that it can secure returns on its investment over time at rates that are competitive with those offered by alternative investment opportunities. When an asset is considered sunk, it has no alternative use, or put differently, it cannot be transferred to another activity. As such, a sunk asset has zero economic value or opportunity cost and the investor no longer expects to secure returns for it. The regulator could have revalued such asset down to opportunity cost for purposes of computing the allowed revenue, but this result in lowering the asset base of the regulated firm below its historic costs or book value. To the extent that the regulator might be perceived as expropriating the assets of the regulated firm if it revalues sunk asset to zero and thus deter future investments, it is not usually practiced. But revaluing sunk assets at replacement costs pointlessly creates windfall gains for the regulated firm at the expense of consumers. These considerations are said to have informed other regulators that have chosen to stick to historic costs when valuing the regulated firm s asset base (Bertram, 2002). If MERALCO s assets existing prior to the start of the regulatory period were valued at historical rather than replacement cost, the opening RAB would have been almost half of the value assigned to it in the regulatory reset. As shown in the next table, assets acquired during 2007 (start of the regulatory period) are valued at current cost in both approaches. Thus the difference between the two approaches lies in the value of the RAB at the beginning of 2007 and its corresponding depreciation. Final Report Page 119

141 Table VI.32 MERALCO s Regulatory Asset Base: Replacement vs. Historical Cost (in million Philippine pesos) Replacement Cost Historical Cost RAB, beginning of ,375 48,819 Less: Depreciation of assets during ,057 2,730 Plus: Inflation of asset base to June ,201 Plus: Approved capital expenditure in ,936 6,936 Less: Depreciation on 2007 additional assets Less: Disposal of assets during Plus: Construction-work-in-progress (CWIP) 2,106 2,106 RAB, end of ,330 54,900 As past and new capital expenditures are rolled forward, the difference in the opening RAB affects the computation of ARR for the entire regulatory period. A detailed calculation of the maximum ARR if MERALCO s assets were not revalued at replacement cost can be traced in subsequent tables. Applicable depreciation is computed in Table V.33; then the average RAB for each year during the regulatory period is shown in Table V.34. Finally, the maximum ARR is shown in Table V.35. Table VI.33 Depreciation Expenditures under Historical Cost Approach in RAB (in million Philippine pesos) Depreciation of the opening RAB at historical 2,730 3,144 3,538 3,885 4,260 cost Depreciation of assets acquired during Depreciation of assets acquired during the ,285 second regulatory period Subtotal 2,909 3,350 4,144 4,848 5,545 plus Disposals 52 0 minus income from disposals Total depreciation on RAB at historical cost 2,915 3,299 4,090 4,792 5,486 Difference between total depreciation on RAB 2,326 1,901 1, at replacement and historical costs Note: See Table 7.6 of Regulatory Reset for Manila Electric Corporation, July 2007 to June 2011, Final Determination, p. 56, for total depreciation on RAB at replacement cost. As expected, the difference in depreciation expenses under the replacement cost and historical cost approaches declines during the regulatory period. In the first year, depreciation under replacement cost approach is P2.3 billion (44%) more than the corresponding depreciation under historical cost. By the fifth and final year in the regulatory period, the difference is whittled down to P152 million (3%). This is because capital expenditures during the regulatory period are valued the same under both approaches. As the opening RAB runs down, the corresponding depreciation expenses fall and hence the difference between the two approaches declines. In contrast, the gap in the values of RAB based on replacement and historical costs shrinks during the regulatory period but not as abrupt compared with depreciation. As shown next, the difference between RAB at replacement and historical costs declines from P49 billion (46%) in the first regulatory year to P45 billion (40%) in the final year. Final Report Page 120

142 Table VI.34 Regulatory Asset Base under Historical Cost Approach (in million Philippine pesos) Opening value of RAB 54,900 59,651 64,042 66,549 Total depreciation on RAB 3,299 4,090 4,792 5,486 Capital expenditure 7,501 8,408 7,183 7,391 Change in assets used over regulatory lives Closing value of RAB 54,900 59,651 64,042 66,549 68,532 Average RAB for the Year 57,276 61,847 65,296 67,541 Difference between RABs at replacement 49,430 48,480 46,801 45,589 45,029 and historical cost Percent change in RAB without asset (45.8) (43.1) (41.1) (40.0) revaluation Note: See Table 7.8 of Regulatory Reset for Manila Electric Corporation, July 2007 to June 2011, Final Determination, p. 56, for average RAB at replacement cost. In any given year, the regulated firm is allowed to generate revenues sufficient to cover for reasonable returns on capital, operating expenses, depreciation expenses and taxes. It is also compensated for the timing difference between the occurrence of the operating expenses and the realization of revenue to cover such expenses. To provide for such compensation, a fraction of operating expenses, labeled working capital, is considered additional capital which is entitled to some returns. In the case of the first group entering into PBR, the working capital factor is 3% of operating expenses. The WACC (12.8%) is applied to the sum of the average RAB for the year and working capital to obtain the return on capital, reflected below. Table VI.35 Maximum Annual Revenue Requirement under Historical Cost Approach (in million Philippine pesos) Return on capital, 12.8% of capital invested 7,375 7,961 8,405 8,694 Average RAB for the year (Table V.34) 57,276 61,847 65,296 67,541 Working capital allowed (3% of OPEX) Subtotal - capital invested 57,613 62,199 65,662 67,923 Operating expenses 11,261 11,740 12,203 12,740 Regulatory depreciation 3,299 4,090 4,792 5,486 Corporate income tax 3,343 3,930 3,916 4,862 Other taxes Subtotal unadjusted ARR 25,575 27,993 29,579 32,013 Plus: Guaranteed Service Level (GSL) allowance (0.5% of ARR) ARR historical cost asset valuation 25,702 28,133 29,727 32,173 ARR ODRC asset valuation 33,852 33,622 36,566 38,122 Percent change in ARR without asset revaluation (24.07) (16.32) (18.70) (15.60) Source: Table 9.5 of Regulatory Reset for Manila Electric Corporation, July 2007 to June 2011, Final Determination, p. 66, for ARR with ODRC asset revaluation. Final Report Page 121

143 There was no revenue cap imposed for 2007 since the regulatory period began in the middle of that year. Still, it is evident from the foregoing that revaluing MERALCO s assets at replacement cost permitted the utility company to reap additional revenues of more than P8 billion in 2008 and almost P6 billion in What is the impact on consumers? This is not easy to discern as the DU is allowed to allocate the maximum allowed revenue to various customer classes. Moreover, the actual revenue allowed of MERALCO for a given year may be different from the maximum ARR in the Final Determination. This is based on the Performance Incentive Scheme (PIS) a key feature of PBR wherein a regulated entity may be rewarded or penalized by as much as 3% of the ARR based on its performance. The service delivery performance of all DUs are monitored and measured against pre-set benchmarks. Based on an annual assessment, the ARR can be adjusted in either direction. Nonetheless, the impact on consumers of asset revaluation can be inferred from the trajectory of maximum average price (MAP) during the regulatory period. Besides PIS, MAP is subject to X-factor (for efficiency) and smoothing. Based on ARR computed with RAB valued at replacement cost, and using 2006 actual average price as starting point, the ERC set the X- factor at 4.62%. This means that the MAP was allowed to change each year by as much as the rate of inflation (consumer price index, CPI) plus 4.62%. Equivalently, MERALCO s distribution charges were allowed to increase annually in real terms by as much as 4.62%. Consequently, the MAP was increasing during the regulatory period. Recall that MERALCO s actual distribution, supply and metering (DSM) charges increased by more than the average CPI during the period 2004 to 2011, as evidenced in Tables II.13 to II.17. If the assets were not revalued, the X-factor should have been 4.98%, hence the change in annual MAP was supposed to be CPI minus 4.98%. 56 Since this rate is higher than the projected CPIs, the MAPs should have been declining instead, as shown in the figure below. More importantly, this could have prevented MERALCO s DSM charges from increasing more than consumer prices. Figure VI.2 Maximum Average Price based on RAB valued at Historical Cost Smoothed ARR per kwh (historical cost) Smoothed ARR per kwh (replacement cost) 56 This is estimated based on the RDWR methodology for calculation of X-factor. See RDWR, pp Final Report Page 122

144 The impact on consumers can also be gleaned from the simulated tariffs under a scenario where assets are not revalued. This assumes that the charges for distribution, supply and metering (DSM) are lowered proportionate to the reduction in ARR. As shown below, even if historical cost valuation of assets reduces the regulatory ARR significantly by as much as 24% in 2008 the changes in final tariffs are significantly less, ranging from 1 to 3 percent. Table VI.36 MERALCO s Tariffs without Asset Revaluation RC HC RC HC RC HC RC HC Residential 1,714 1,648 1,666 1,616 2,004 1,993 2,049 1,983 Percent change (3.84) (2.99) (3.53) (3.25) Commercial 27,028 26,247 26,152 25,506 31,137 30,184 32,441 31,553 Percent change (2.89) (2.47) (3.06) (2.74) LV Industrial (P 000) Percent change (1.46) (1.52) (2.01) (1.85) HV Industrial (P 000) 1,372 1,356 1,326 1,312 1,619 1,598 1,675 1,654 Percent change (1.14) (1.04) (1.29) (1.23) Note: RC = replacement cost; HC = historical cost. The foregoing analysis is replicated for five other DUs belonging to the first and second group of PBR entrants, namely CEPALCO, DECORP, ILPI, CLPC and MECO. But unlike in the case of MERALCO, the historical costs (book value) of the assets of these five DUs are not known. Such information is necessary to establish the RAB if the assets were not revalued. However, the Regulatory Reset Final Determination for these DUs show historical cost depreciation expenses of the optimized assets. To estimate the book value of the optimized assets at the date of revaluation, it is assumed that the historical and ODRC depreciation expenses are proportional to the corresponding values of assets measured at historical and replacement cost basis. Thus taking the ratio of historical to ODRC depreciation and multiplying this by ODRC assets generates estimate of historical costs of assets shown in the third column of Table V.37. It is not feasible to extend this approach to the third and fourth PBR entrants for which there was also no available information on the historical cost on their respective assets since their Final Determination documents do not show historical cost depreciation expenses. As a result, the impact of asset revaluation can only be assessed for the first two groups of entrants. Table VI.37 Regulatory Impact of No Asset Revaluation in Selected DUs (value in million Philippine pesos) ODRC Estimated Historical Cost % Change in RAB, 2011 % Change in ARR, 2011 ODRC X-factor, % Estimated X-factor, % CEPALCO 1,946 1,383 (23.7) (10.6) DECORP (66.4) (19.5) ILPI (10.9) (7.4) CLPC MECO (32.7) (22.2) MERALCO 96,375 48,819 (40.0) (15.6) Final Report Page 123

145 As can be inferred from the preceding table, except in the case of CLPC, the revaluation of assets using replacement costs inflated the RAB by as much as 66% in the case of DECORP. For CLPC, however, the asset revaluation has an opposite effect, which suggests that the replacement costs of existing assets are lower than their book values. ARR changes with RAB, so the asset revaluation increased the ARR of most DUs, and thus allowed them to raise their DSM charges to consumers. The impact of the asset revaluation manifests as well in the computed regulatory X-factor (efficiency index), which turns out to be negative for all DUs entering PBR. The purpose is to allow the DUs raise revenues sufficient to cover for the inflated asset base. 57 This also means that the DSM charges were raised by more than the price inflation during the first regulatory period. For example, CEPALCO s X-factor of -2.62% implies that it was permitted to adjust its charges annually by the forecast CPI plus 2.62% during the regulatory period In the case of DECORP, ILPI and CLPC, the ERC even had to adjust the initially computed ARR to stave off potential large increases in customer tariffs, but still the final X-factors have negative values. Without asset revaluation, the X-factor would have had positive values for the first group of entrants (MERALCO, CEPALCO and DECORP), and less negative for the second group except CLPC. Nonetheless, it is useful to note that the perverse effect on X-factor lasted only in the first period. In the next regulatory period for the first group of entrants (July 2011 to June 2015), the X-factors have positive values, namely 4.67, 4.26 and 4.64 percent for MERALCO, CEPALCO and DECORP, respectively. Even with negative X-factors, the increases in tariffs are moderated by the relatively small share of DSM less than 10 percent in industrial and about 20 percent for residential tariffs. Keeping the assets valued at historical cost for purposes of estimating the RAB could have averted increases of about 4.7% in CEPALCO s residential tariff and 2.5% in MECO s industrial tariff. Table VI.38 Impact on Tariffs of Selected DUs without Asset Revaluation (in percent) Residential Commercial LV Industrial HV Industrial CEPALCO (4.73) (2.96) (2.56) (1.76) DECORP (4.58) (2.45) (2.63) (2.14) ILPI (1.89) (1.67) (1.24) (1.06) MECO (3.38) (2.42) (3.18) (2.46) MERALCO (3.25) (2.74) (1.85) (1.23) 57 This is an implicit way of allowing the DUs build up their financial capability to replace the assets they already have. Final Report Page 124

146 VII. Synthesis and Conclusions The introduction of competition in the Philippine electricity market gave rise to expectations that more efficient supply and lower prices are forthcoming. But the first decade of reforms disappointed observers. Electricity tariffs for different customer classes increased at an average annual rate of 6.9 to 8.7 percent, exceeding average inflation of 4.8 percent during the period. The price adjustments were occasioned by the removal of inter- and intra-class subsidies, introduction of new taxes (specifically VAT in 2006), and increases in distribution charges. Yet what concerns policymakers more than the unexpected trend in prices is that the Philippine rates are still several times higher than in other countries with whom it competes for investments and trade. Residential customers in the Philippines, for instance, pay nearly four times the price levied on their counterpart in Indonesia, while industrial customers are charged at least 60 percent more than their equivalent in Thailand. Why are prices much higher in the Philippines than elsewhere? The most visible explanation is the tax. The average tax embedded in Philippine tariffs is about 9%, compared to flat rates of 6% in Malaysia and 7% in Singapore and Thailand, although Indonesia s tax is 12.5%. The more significant difference is however accounted for by implicit subsidies to state-owned utilities. In 2011 alone, the Indonesian utility received US$10.24 billion transfers. The Malaysian utility received a relatively smaller direct transfers (about US$153 million in 2010; undisclosed in 2011), but hefty fuel discount of at least 26% on the market price of indigenous fuel. The subsidies in Thailand are least known as it is set in the domestic price of locally-sourced natural gas. Based on the conservative estimates of the IEA, the subsidy amounted to about Php1.51, 0.39 and 1.67 per kwh in Indonesia, Malaysia and Thailand, respectively. But even after adjusting for differences in taxes and subsidies, the Philippine tariffs still come out higher than in these economies except Singapore. The price differentials are shown below. Table VII.1 Comparative 2011 Electricity Tariffs after Adjusting for Taxes and Subsidies* (per kwh, in Philippine peso) PHL SGP INA MAL THA Residential Low voltage commercial Low voltage industrial High voltage industrial *Based on IEA s subsidy estimates. Thus, despite adjustments in taxes and subsidies, Philippine residential and (high voltage) industrial tariffs are, respectively, 2.4 and 1.3 times Indonesia s, and 2.6 and 1.2 times Malaysia s. There are possible explanations for these residual differences. The most obvious is that the IEA estimates are much lower than actual. In fact, there are higher estimates of the subsidies. For Indonesia, the direct transfers to PLN is twice IEA s estimate, while for Malaysia, the price adjustments contemplated in the 10 th Malaysian Plan suggest a subsidy about six times IEA s. If these higher estimates were used, the tariff differences would be narrower and Philippine tariffs become comparable to Malaysia s except for residential customers. Final Report Page 125

147 Table VII.2 Indonesian and Malaysian Subsidy-Adjusted Tariffs Compared to Philippine Tariffs (per kwh, in Philippine peso) Indonesia Malaysia Without tax & subsidies a/ Difference with Phil. tariff Without tax & subsidies b/ Difference with Phil. tariff Residential Low voltage commercial Low voltage industrial High voltage industrial *After adjusting for taxes and subsidies a/ Using BPP; b/ Based on subsidies deduced from the 10 th Malaysian Plan. The huge difference in residential tariffs between the Philippines and other countries is however due to the fact that regulated prices in the latter are not aligned with costs. Market reforms, on the other hand, realigned Philippine tariffs with costs. The presence of inter-class subsidy in other countries is evident in the preceding Tables. If prices were aligned with costs, then residential tariffs would have been higher than industrial s, but the opposite is true in Indonesia, Malaysia and Thailand. Consequently, despite tax and subsidy adjustments, the Philippine average residential tariff is still significantly greater than in these countries by 48, 57 and 45 percent, respectively. Differences in market structures are also important, although it is extremely difficult to measure their contributions to tariff differences. Clearly, the industry structure in Indonesia, Malaysia and Thailand vertically integrated and managed by public utilities is bound to produce different prices compared to a market-based, unbundled industry such as the one prevailing in the Philippines and Singapore. The Thai public utilities, for example, subsist on a return on capital of 7.5% for EGAT and 5.73% for MEA and PEA, compared to about 15% for private DUs in the Philippines. Moreover, when the industry is disintegrated or unbundled, profit margins at each stage of production could pile up on prices, unless market competition and prudent regulation ensure that the margins are reduced to competitive level. 58 If regulation fails on facilitating effective competition after the industry is unbundled, then prices are inevitably higher in the restructured industry than under vertical integration. 59 Finally, some price differences reflect inherent differences in costs of supply due to network conditions, load demand profile and generation mix, among others. These differences can only be properly diagnosed by a cost of service study, which is beyond the scope of this work. Even if one can rationalize why Philippine electricity prices are not competitive, there is value in inquiring if there are policy adjustments that could reduce them without distorting market signals, i.e., misaligning prices and costs. The current proposed legislations to lower electricity tariffs is a mixed batch of ad hoc and socially-oriented policies. Some call for changes in taxes and government share in indigenous fuel. Other proposals are however outright distortionary, such as the removal of recoverable rate of system losses and provision of subsidies to low- 58 The disintegration of a monopoly into two independent units with the same market power as their predecessor results in so called double marginalization, or the exercise of market power at successive vertical layers in the supply chain (Lerner, 1934). It leads to a higher retail price but possibly lower combined profits for the supply chain than would arise if the monopoly remains vertically integrated. 59 An inquiry on whether regulation is faltering in stimulating sufficient and effective competition that could raise efficiency and reduce costs and prices is beyond the scope of this paper. Final Report Page 126

148 income consumers. The counterfactual simulations of some of the proposed policy changes produce the following potential adjustments in MERALCO tariffs: Table VII.3 Potential Policy Changes to Lower MERALCO Tariffs (per kwh, in Philippine peso) Residential Low Voltage Commercial Low Voltage Industrial High Voltage Industrial Average, Policy interventions: Zero VAT Elimination of all subsidies (lifeline and senior citizens discounts) No asset revaluation Proportionate geothermal rebate Uniform natural gas rebate Total potential tariff reduction None of the foregoing results should be viewed as recommendation for any policy change. The merit of rebating to electricity consumers the government share on the utilization of indigenous fuels is debatable since it tends to distort the relative prices of fuels. Similarly, the removal of VAT on electricity would mean less fiscal resources for other public services, and thus poses the issue of whose interests should prevail. Even as asset revaluation increases distribution charges, there are conceptual and practical arguments that justify the use of replacement, instead of historical, costs in asset pricing. Moreover rebate on the basis of kwh consumption is clearly problematic since it favors heavy users and is thus a disincentive for energy conservation. Therefore, the results of the counterfactual simulations should be viewed as mere demonstration of the remaining influence policies have on electricity tariffs. As a final note, there remains the issue of whether the lack of competitiveness of Philippine electricity tariffs could be used as basis for rejecting the reforms implemented over the past decade. It is worth underscoring the fact that Indonesian and Malaysian policymakers understand the need to restructure their respective industries from the traditional verticallyintegrated, state-managed structure to one that is market-based and private sector-led. They recognize that their current tariff structures and fuel subsidies are unsustainable; that their public utilities are underperforming because the market structure does not create enough incentives for efficiency; and that the inefficiencies in the electricity sector are affecting the rest of the economy as it attracts industries dependent on subsidized energy. But just like the Philippines more than a decade ago, these economies are constrained by political realities from pursuing market reforms. Therefore, the failure of the Philippines to reap the reform dividends of lower electricity prices should not be blamed on the difficult path it has taken when other economies recognize the need for it. Final Report Page 127

149 Annex I. Customer Classes Used in Model Cases DU Commercial LV Industrial LV Industrial HV MERALCO General Service B NIS General Power Small Industrial Medium General Power 13.8/13.2 KV Industrial Large Secondary SFELAPCO Commercial Industrial Industrial CELCOR Large Commercial Large Industrial Large Industrial DECORP General Retail General Power Retail General Power Retail LUECO Commercial X-2 Industrial Industrial SUBIC AEC Commercial - Gen SVC 3 Small Industrial Large Industrial BLCI Commercial IEEC Commercial Industrial Industrial TEI Small Commercial Secondary Primary MECO Commercial Industrial Industrial VECO General Service General Power General Power PECO Commercial General Power General Power CEPALCO General Power 47A- HLF - Secondary- Metered DLPC COLIGHT CEDC GS-4 Small Industrial Large Industrial ILPI Commercial General Power General Power INEC Small Commercial - LV Industrial - LV Industrial - HV ISECO Commercial - LV Industrial - LV Industrial - HV LUELCO Commercial - LV Industrial - HV PANELCO 1 Commercial - LV General Power - LV General Power - HV PANELCO 3 Commercial - LV Industrial - LV Industrial - HV CENPELCO BATANELCO Commercial - LV CAGELCO 1 Commercial - LV Industrial - LV Industrial - HV CAGELCO 2 Commercial - LV ISELCO 1 Commercial - LV Industrial - LV Industrial - HV ISELCO 2 Commercial - LV Industrial - HV NUVELCO Commercial - LV Industrial - LV Industrial - HV QUIRELCO Small Commercial - LV Industrial - LV AURELCO Commercial - LV Industrial - LV TARELCO 1 Commercial - LV Industrial - LV TARELCO 2 Small Commercial - LV Industrial - LV Industrial - HV NEECO 1 Commercial - LV Industrial - LV Industrial - HV NEECO 2 Commercial - LV Industrial - LV Industrial - HV AREA 1 NEECO 2 Small Commercial - LV Industrial - HV AREA 2 PRESCO Commercial - LV SAJELCO Commercial - LV Industrial - LV Industrial - HV PELCO 1 Commercial - LV Industrial - LV Industrial - HV Final Report Page 128

150 DU Commercial LV Industrial LV Industrial HV PELCO 2 Commercial - LV Industrial - LV Industrial - HV PELCO 3 Commercial - LV Industrial - LV PENELCO Commercial - LV Industrial - LV Industrial - HV ZAMECO 1 Commercial - LV Industrial - HV ZAMECO 2 Commercial - LV Industrial - LV Industrial - HV FLECO Commercial - LV Industrial - LV Industrial - HV BATELEC 1 Commercial - LV Industrial - LV Industrial - HV BATELEC 2 Commercial - LV Small Industrial - LV Large Industrial - HV QUEZELCO 1 QUEZELCO 2 Commercial - LV Industrial - LV LUBELCO Commercial - LV Industrial - LV OMECO Commercial - LV Industrial - LV ORMECO Commercial - LV Industrial - LV MARELCO Commercial Industrial - LV TIELCO Commercial Industrial - LV ROMELCO Commercial Industrial - LV BISELCO Small Commercial - LV Industrial - LV PALECO Commercial Industrial - LV CANORECO Commercial - LV Industrial - LV Industrial - HV CASURECO 1 Commercial - LV Industrial - LV Industrial - HV CASURECO 2 Commercial - LV Industrial - LV Industrial - HV CASURECO 3 Commercial - LV Industrial - LV CASURECO 4 Commercial - LV Industrial - LV Industrial - HV ALECO LV LV HV SORECO 1 Commercial - LV Industrial - LV Industrial - HV SORECO 2 Commercial - LV Industrial - LV Industrial - HV FICELCO Commercial - LV MASELCO Commercial - LV Industrial - LV TISELCO Commercial AKELCO Commercial - LV Industrial - LV CAPELCO Commercial - LV Industrial - LV Industrial - HV ANTECO GUIMELCO Commercial - LV Industrial - LV ILECO 1 Commercial - LV Industrial - LV Industrial - HV ILECO 2 Commercial - LV Industrial - LV Industrial - HV ILECO 3 Commercial - LV Industrial - LV VRESCO Commercial - LV Industrial - LV Industrial - HV CENECO Small Commercial - LV Primary Metering - HV NOCECO Commercial - LV Industrial - LV Large Industrial - HV NORECO 1 NORECO 2 Commercial - LV Industrial - LV HV BANELCO Commercial - LV Industrial - LV CEBECO 1 Commercial - LV Industrial - LV Industrial - HV CEBECO 2 Commercial - LV Industrial - LV Industrial - HV CEBECO 3 Commercial - LV Industrial - LV Industrial - HV PROSIELCO Small Commercial - LV Industrial - LV CELCO Commercial - LV Industrial - LV BOHECO 1 Small Commercial - LV Industrial - HV BOHECO 2 Commercial - LV Industrial - LV Industrial - HV Final Report Page 129

151 DU Commercial LV Industrial LV Industrial HV DORELCO Small Commercial - LV Industrial LEYECO 2 Commercial - LV Industrial - HV LEYECO 3 Commercial - LV Industrial - LV LEYECO 4 Commercial - LV Industrial - LV Industrial - HV LEYECO 5 Commercial - LV Industrial - LV Industrial - HV SOLECO Commercial - LV Industrial - HV BILECO Commercial - LV NORSAMELCO Commercial - LV Industrial - LV SAMELCO 1 Commercial - LV Industrial - HV SAMELCO 2 Commercial - LV ESAMELCO Commercial - LV Industrial - LV ZAMSURECO 1 Commercial - LV Industrial - LV Industrial - HV ZAMSURECO 2 Commercial - LV Industrial - LV ZANECO Commercial - LV Industrial - HV ZAMCELCO Commercial - LV Industrial - LV Industrial - HV MOELCI 1 Commercial - LV Industrial - HV MOELCI 2 Commercial - LV Industrial - HV MORESCO 1 MORESCO 2 Commercial - LV Industrial - LV Industrial - HV FIBECO Commercial - LV Industrial - LV Industrial - HV BUSECO Commercial - LV Industrial - LV Industrial - HV CAMELCO Commercial - LV LANECO Commercial - LV Industrial - LV DORECO Commercial - LV Industrial - LV Industrial - HV DANECO Commercial - LV Industrial - LV Large Industrial - HV DASURECO Commercial - LV Industrial - LV Industrial - HV COTELCO Commercial - LV Industrial - LV SOCOTECO 1 LV LV HV SOCOTECO 2 Commercial - LV Industrial - LV Industrial - HV SUKELCO Commercial - LV Industrial - LV ABRECO Commercial - LV Industrial - LV MOPRECO Commercial - LV IFELCO Commercial - LV Industrial - LV BENECO Commercial - LV Industrial - LV KAELCO Commercial - LV Industrial - LV Industrial - HV LASURECO Commercial - LV Industrial - LV SULECO MAGELCO SIASELCO Commercial - LV Industrial - LV TAWELCO CASELCO ANECO Commercial - LV Industrial - HV ASELCO Commercial - LV Industrial - LV Industrial - HV SURNECO Commercial - LV HV SIARELCO Commercial - LV DIELCO Commercial - LV SURSECO 1 Small Commercial - LV Industrial - HV SURSECO 2 Commercial - LV Industrial - LV Industrial - HV BASELCO Commercial - LV Industrial - LV Final Report Page 130

152 Annex II.1 Composition of Residential Tariff for 200 kwh Monthly Consumption in 2011, by DU (Philippine peso per kwh) DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff ABRECO 1, (60.00) (8.58) , AEC 1, , AKELCO 1, , ALECO , ANECO (61.92) , ASELCO (62.19) , AURELCO 1, , BATANELCO (60.00) , BATELEC (60.00) , BATELEC (2.47) , BENECO (43.66) , BILECO (7.54) , BLCI (54.79) , BOHECO (2.93) , BUSECO (60.00) , CAGELCO , CAGELCO , CAMELCO (60.00) , CANORECO (39.11) , CASURECO (60.00) , CASURECO 2 1, , CASURECO (21.28) , CASURECO 4 1, , CEBECO (19.76) , CEBECO (39.51) , CEBECO 3 1, , CEDC (78.66) , CELCO 1, (60.00) , CELCOR 1, , CEPALCO (56.28) , COLIGHT (59.83) , COTELCO (62.06) , DANECO (60.00) , DASURECO (31.52) , DECORP 1, , DIELCO 1, (60.00) , DLPC (50.97) , DORECO (60.00) , ESAMELCO (42.70) , Final Report Page 131

153 DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff FIBECO (105.06) , FICELCO 1, (66.72) , FLECO 1, (17.50) , GUIMELCO 1, , IEEC 1, , IFELCO 1, , ILECO 1 1, , ILECO 2 1, , ILECO (60.00) , ILPI (60.00) , INEC , ISECO , ISELCO 1 1, (2.85) , KAELCO , LASURECO (60.00) , LEYECO (16.90) , LEYECO (60.00) , LEYECO (42.70) , LEYECO (43.76) , LUBELCO (60.00) , LUECO (59.91) , LUELCO 1, , MARELCO 1, (60.00) , MASELCO 1, (60.00) , MECO (61.99) , MERALCO 1, (0.22) , MOELCI (60.00) , MOELCI (60.00) , MOPRECO , MORESCO (60.00) , NEECO , NEECO 2 AREA , NEECO 2 AREA , NOCECO (25.43) , NORECO 2 1, (19.62) , NORSAMELCO (53.69) , NUVELCO 1, , OMECO 1, (60.00) , ORMECO 1, (37.74) , PANELCO 1 1, (10.56) , PANELCO , PECO 1, , Final Report Page 132

154 DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff PELCO 1 1, (7.90) , PELCO , PELCO 3 1, (2.35) , PENELCO , PRESCO 1, , PROSIELCO 1, (60.00) , QUEZELCO (60.00) , QUIRELCO , ROMELCO 1, (49.51) , SAJELCO 1, , SAMELCO (15.86) , SAMELCO (44.54) , SFELAPCO (0.00) , SIARELCO (60.00) , SOCOTECO (60.00) , SOCOTECO (8.86) , SOLECO (61.30) , SORECO , SORECO 2 1, , SUKELCO (60.00) , SURSECO (60.00) , TARELCO 1 1, , TARELCO , TEI 1, (0.51) , TIELCO 1, (60.00) , VECO 1, (20.03) , ZAMCELCO (61.78) , ZAMECO 1 1, , ZAMECO 2 1, (4.93) , ZAMSURECO (60.00) , ZAMSURECO (60.00) , ZANECO (72.34) , All DUs (9.91) , Final Report Page 133

155 Annex II.2 Composition of Commercial Tariff for 3 MWh Monthly Consumption in 2011, by DU (Philippine peso per kwh) DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff ABRECO 15, , , , (128.70) , , AEC 17, , , , , , AKELCO 17, , , , , ALECO 13, , , , , ANECO 8, , , , (31.09) , ASELCO 8, , , , (32.02) , AURELCO 18, , , , , , BATANELCO 14, , , , , BATELEC 1 14, , , , , , BATELEC 2 14, , , , (35.17) , BENECO 13, , , , (3.60) , , BILECO 9, , , , , BLCI 11, , , , , BOHECO 1 14, , , , (59.09) , , BUSECO 8, , , , , , CAGELCO 1 13, , , , , CAGELCO 2 13, , , , , CAMELCO 8, , , , , , CANORECO 14, , , , , CASURECO 1 14, , , , , , CASURECO 2 16, , , , , , CASURECO 3 13, , , , , CASURECO 4 15, , , , , CEBECO 1 13, , , , , CEBECO 2 13, , , , , , CEBECO 3 15, , , , , CEDC 12, , , (287.46) , , CELCO 22, , , , , CELCOR 19, , , , , , , CEPALCO 10, , , , , , , COLIGHT 8, , , , , , , COTELCO 8, , , , , , DANECO 8, , , , , , DASURECO 9, , , , , , DECORP 15, , , , , , DIELCO 19, , , , , DLPC 10, , , , , , DORECO 8, , , , , , ESAMELCO 12, , , , , FIBECO 8, , , , (677.56) , Final Report Page 134

156 DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff FICELCO 18, , , , , FLECO 15, , , , (94.34) , , GUIMELCO 18, , , , , , IEEC 15, , , , , IFELCO 16, , , , , , ILECO 1 18, , , , , , ILECO 2 15, , , , , , ILECO 3 14, , , , , , ILPI 8, , , , , INEC 14, , , , , , ISECO 14, , , , , , ISELCO 1 15, , , , (43.24) , , KAELCO 14, , , , , , LASURECO 8, , , , , , LEYECO 2 12, , , , , LEYECO 3 12, , , , , , LEYECO 4 11, , , , , LEYECO 5 12, , , , , LUBELCO 14, , , , , LUECO 14, , , , , , LUELCO 16, , , , , , MARELCO 19, , , , , MASELCO 15, , , , , MECO 14, , , (104.70) , , MERALCO 16, , , , , , MOELCI 1 8, , , , , MOELCI 2 8, , , , , MOPRECO 14, , , , , , MORESCO 2 8, , , , , , NEECO 1 13, , , , , NEECO 2 14, , , , , , AREA 1 NEECO 2 14, , , , , AREA 2 NOCECO 13, , , , , , NORECO 2 15, , , , , , NORSAMELCO 12, , , , , NUVELCO 15, , , , , , OMECO 18, , , , , ORMECO 20, , , , , PANELCO 1 17, , , , , , PANELCO 3 14, , , , , , Final Report Page 135

157 DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff PECO 21, , , , , PELCO 1 16, , , , , , PELCO 2 14, , , , , , PELCO 3 15, , , , (24.38) - 2, , PENELCO 14, , , , , , PRESCO 16, , , , , , PROSIELCO 22, , , , , QUEZELCO 2 14, , , , , QUIRELCO 13, , , , , ROMELCO 18, , , , , SAJELCO 17, , , , , , SAMELCO 1 12, , , , , , SAMELCO 2 12, , , , , SFELAPCO 13, , , , , SIARELCO 7, , , , , , SOCOTECO 1 8, , , , , SOCOTECO 2 9, , , , , SOLECO 12, , , , (19.50) , SORECO 1 12, , , , , SORECO 2 15, , , , , , SUKELCO 8, , , , , , SURSECO 1 8, , , , , , TARELCO 1 15, , , , , , TARELCO 2 13, , , , TEI 16, , , , (8.05) , , TIELCO 19, , , , , VECO 15, , , , , , , ZAMCELCO 8, , , , (26.66) , ZAMECO 1 17, , , , , , ZAMECO 2 17, , , , , , ZAMSURECO1 8, , , , , , ZAMSURECO2 8, , , , , ZANECO 7, , , , (154.57) , All DUs 15, , , , , , Final Report Page 136

158 Annex II.3 Composition of Low Voltage Industrial Tariff for 50 MWh Monthly Consumption in 2011, by DU (in thousand Philippine pesos per kwh) DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff ABRECO (2.15) AEC AKELCO ALECO ASELCO (0.00) AURELCO BATELEC BATELEC (0.64) BENECO (0.06) BUSECO CAGELCO CANORECO CASURECO CASURECO CASURECO CEBECO CEBECO CEBECO CEDC (3.21) CELCO CELCOR CEPALCO COLIGHT COTELCO DANECO DASURECO DECORP DLPC DORECO ESAMELCO FIBECO (11.29) FLECO (1.64) GUIMELCO IEEC IFELCO ILECO ILECO ILECO ILPI INEC Final Report Page 137

159 DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff ISECO ISELCO (0.71) KAELCO LASURECO LEYECO LEYECO LEYECO LUBELCO LUECO MARELCO MASELCO MECO MERALCO MORESCO NEECO NEECO AREA 1 NOCECO NORECO NORSAMELCO NUVELCO OMECO ORMECO PANELCO PANELCO PECO PELCO PELCO PELCO (0.48) PENELCO PROSIELCO QUEZELCO QUIRELCO ROMELCO SAJELCO SFELAPCO SOCOTECO SOCOTECO SORECO SORECO SUKELCO TARELCO Final Report Page 138

160 DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff TARELCO TEI (0.21) TIELCO VECO ZAMCELCO (0.45) ZAMECO ZAMSURECO ZAMSURECO (2.15) All DUs Final Report Page 139

161 Annex II.4 Composition of High Voltage Industrial Tariff for 200 MWh Monthly Consumption in 2011, by DU (Philippine peso per kwh) DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff AEC 1, , ALECO , ANECO (1.88) , ASELCO (2.14) , BATELEC , BATELEC (2.19) , BOHECO (3.52) , BUSECO , CAGELCO , CANORECO , CASURECO 2 1, , CASURECO 4 1, , CEBECO , CEBECO , CEBECO 3 1, , CEDC (18.78) , CELCOR 1, , CEPALCO , COLIGHT , DANECO , DECORP 1, , DLPC , DORECO , FIBECO (44.86) , FLECO 1, (7.02) , IEEC 1, , ILECO 1 1, , ILECO , ILPI , INEC 1, , ISECO , ISELCO 1 1, (2.70) , KAELCO , LEYECO , LEYECO , LEYECO , LUECO , LUELCO 1, , MECO , MERALCO 1, , Final Report Page 140

162 DU Generation Transmission Distribution Supply Metering System loss Temporary Adjustments Universal Charges Subsidy Other Taxes VAT Tariff MOELCI , MOELCI , MORESCO , NEECO , NEECO , AREA 1 NEECO , AREA 2 NOCECO , NORECO 2 1, , NUVELCO 1, , PANELCO 1 1, , PANELCO , PECO 1, , PELCO 1 1, , PELCO , PENELCO , SAJELCO 1, , SAMELCO , SFELAPCO , SOCOTECO SOCOTECO , SOLECO (1.30) , SORECO , SORECO 2 1, , SURSECO , TARELCO , TEI 1, (0.99) , VECO 1, , ZAMCELCO (1.92) , ZAMECO 1 1, , ZAMECO 2 1, , ZAMSURECO , ZANECO (6.97) , All DUs 1, , Final Report Page 141

163 Annex III.1.1 Policy Simulation Results I for Residential Tariff, by DU (in Philippine pesos) DU Actual Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT ABRECO 2, , , , , , , , AEC 1, , , , , , , , AKELCO 1, , , , , , , , ALECO 1, , , , , , , , ANECO 1, , , , , , , , ASELCO 1, , , , , , , , AURELCO 2, , , , , , , , BATANELCO 1, , , , , , , , BATELEC 1 1, , , , , , , , BATELEC 2 1, , , , , , , , BENECO 1, , , , , , , , BILECO 1, , , , , , , , BLCI 1, , , , , , , , BOHECO 1 1, , , , , , , , BUSECO 1, , , , , , , , CAGELCO 1 1, , , , , , , , CAGELCO 2 1, , , , , , , , CAMELCO 1, , , , , , , , CANORECO 1, , , , , , , , CASURECO 1 2, , , , , , , , CASURECO 2 2, , , , , , , , CASURECO 3 2, , , , , , , , CASURECO 4 2, , , , , , , , CEBECO 1 1, , , , , , , , CEBECO 2 1, , , , , , , , CEBECO 3 1, , , , , , , , CEDC 1, , , , , , , , CELCO 2, , , , , , , , CELCOR 2, , , , , , , , CEPALCO 1, , , , , , , , COLIGHT 1, , , , , , , , COTELCO 1, , , , , , , , DANECO 1, , , , , , , , DASURECO 1, , , , , , , , DECORP 1, , , , , , , , DIELCO 2, , , , , , , , Final Report Page 142

164 DU Actual Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT DLPC 1, , , , , , , , DORECO 1, , , , , , , , ESAMELCO 1, , , , , , , , FIBECO 1, , , , , , , , FICELCO 2, , , , , , , , FLECO 1, , , , , , , , GUIMELCO 2, , , , , , , , IEEC 1, , , , , , , , IFELCO 2, , , , , , , , ILECO 1 2, , , , , , , , ILECO 2 2, , , , , , , , ILECO 3 2, , , , , , , , ILPI 1, , , , , , , , INEC 1, , , , , , , , ISECO 1, , , , , , , , ISELCO 1 1, , , , , , , , KAELCO 2, , , , , , , , LASURECO 1, , , , , , , , LEYECO 2 1, , , , , , , , LEYECO 3 1, , , , , , , , LEYECO 4 1, , , , , , , , LEYECO 5 1, , , , , , , , LUBELCO 2, , , , , , , , LUECO 1, , , , , , , , LUELCO 2, , , , , , , , MARELCO 2, , , , , , , , MASELCO 1, , , , , , , , MECO 1, , , , , , , , MERALCO 2, , , , , , , , MOELCI 1 1, , , , , , , , MOELCI 2 1, , , , , , , , MOPRECO 2, , , , , , , , MORESCO 2 1, , , , , , , , NEECO 1 1, , , , , , , , NEECO 2 AREA 1 2, , , , , , , , NEECO 2 AREA 2 1, , , , , , , , NOCECO 1, , , , , , , , NORECO 2 1, , , , , , , , Final Report Page 143

165 DU Actual Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT NORSAMELCO 2, , , , , , , , NUVELCO 2, , , , , , , , OMECO 2, , , , , , , , ORMECO 2, , , , , , , , PANELCO 1 2, , , , , , , , PANELCO 3 1, , , , , , , , PECO 2, , , , , , , , PELCO 1 2, , , , , , , , PELCO 2 1, , , , , , , , PELCO 3 1, , , , , , , , PENELCO 1, , , , , , , , PRESCO 2, , , , , , , , PROSIELCO 2, , , , , , , , QUEZELCO 2 2, , , , , , , , QUIRELCO 2, , , , , , , , ROMELCO 2, , , , , , , , SAJELCO 2, , , , , , , , SAMELCO 1 1, , , , , , , , SAMELCO 2 1, , , , , , , , SFELAPCO 1, , , , , , , , SIARELCO 1, , , , , , , , SOCOTECO 1 1, , , , , , , , SOCOTECO 2 1, , , , , , , , SOLECO 1, , , , , , , , SORECO 1 2, , , , , , , , SORECO 2 2, , , , , , , , SUKELCO 1, , , , , , , , SURSECO 1 1, , , , , , , , TARELCO 1 1, , , , , , , , TARELCO 2 1, , , , , , , , TEI 2, , , , , , , , TIELCO 2, , , , , , , , VECO 1, , , , , , , , ZAMCELCO 1, , , , , , , , ZAMECO 1 2, , , , , , , , ZAMECO 2 2, , , , , , , , ZAMSURECO 1 1, , , , , , , , ZAMSURECO 2 1, , , , , , , , Final Report Page 144

166 DU Actual Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT ZANECO 1, , , , , , , , ALL 1, , , , , , , , Final Report Page 145

167 Annex III.1.2 Policy Simulation Results II for Residential Tariff, by DU (Philippine peso per kwh) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Uniform Natgas royalties rebate to all customers DU Revenue Neutral VAT (10.5%) Natgas royalties rebate to Luzon ABRECO 2, , , , , , , AEC 1, , , , , , , AKELCO 2, , , , , , , ALECO 1, , , , , , , ANECO 1, , , , , , , ASELCO 1, , , , , , , AURELCO 2, , , , , , , BATANELCO 1, , , , , , , BATELEC 1 1, , , , , , , BATELEC 2 1, , , , , , , BENECO 1, , , , , , , BILECO 1, , , , , , , BLCI 1, , , , , , , BOHECO 1 1, , , , , , , BUSECO 1, , , , , , , CAGELCO 1 1, , , , , , , CAGELCO 2 1, , , , , , , CAMELCO 1, , , , , , , CANORECO 1, , , , , , , CASURECO 1 2, , , , , , , CASURECO 2 2, , , , , , , CASURECO 3 2, , , , , , , CASURECO 4 2, , , , , , , CEBECO 1 1, , , , , , , CEBECO 2 1, , , , , , , CEBECO 3 1, , , , , , , CEDC 1, , , , , , , CELCO 2, , , , , , , CELCOR 2, , , , , , , CEPALCO 2, , , , , , , COLIGHT 1, , , , , , , Final Report Page 146

168 Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Uniform Natgas royalties rebate to all customers DU Revenue Neutral VAT (10.5%) Natgas royalties rebate to Luzon COTELCO 1, , , , , , , DANECO 1, , , , , , , DASURECO 1, , , , , , , DECORP 1, , , , , , , DIELCO 2, , , , , , , DLPC 1, , , , , , , DORECO 1, , , , , , , ESAMELCO 1, , , , , , , FIBECO 1, , , , , , , FICELCO 2, , , , , , , FLECO 1, , , , , , , GUIMELCO 2, , , , , , , IEEC 2, , , , , , , IFELCO 2, , , , , , , ILECO 1 2, , , , , , , ILECO 2 2, , , , , , , ILECO 3 2, , , , , , , ILPI 1, , , , , , , INEC 1, , , , , , , ISECO 1, , , , , , , ISELCO 1 1, , , , , , , KAELCO 2, , , , , , , LASURECO 1, , , , , , , LEYECO 2 1, , , , , , , LEYECO 3 2, , , , , , , LEYECO 4 1, , , , , , , LEYECO 5 1, , , , , , , LUBELCO 2, , , , , , , LUECO 1, , , , , , , LUELCO 2, , , , , , , MARELCO 2, , , , , , , MASELCO 1, , , , , , , MECO 1, , , , , , , MERALCO 2, , , , , , , Final Report Page 147

169 Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Uniform Natgas royalties rebate to all customers DU Revenue Neutral VAT (10.5%) Natgas royalties rebate to Luzon MOELCI 1 1, , , , , , , MOELCI 2 1, , , , , , , MOPRECO 2, , , , , , , MORESCO 2 1, , , , , , , NEECO 1 1, , , , , , , NEECO 2 AREA 1 2, , , , , , , NEECO 2 AREA 2 1, , , , , , , NOCECO 1, , , , , , , NORECO 2 1, , , , , , , NORSAMELCO 2, , , , , , , NUVELCO 2, , , , , , OMECO 2, , , , , , , ORMECO 2, , , , , , , PANELCO 1 2, , , , , , , PANELCO 3 2, , , , , , , PECO 2, , , , , , , PELCO 1 2, , , , , , , PELCO 2 1, , , , , , , PELCO 3 1, , , , , , , PENELCO 1, , , , , , , PRESCO 2, , , , , , , PROSIELCO 2, , , , , , , QUEZELCO 2 2, , , , , , , QUIRELCO 2, , , , , , , ROMELCO 2, , , , , , , SAJELCO 2, , , , , , , SAMELCO 1 1, , , , , , , SAMELCO 2 1, , , , , , , SFELAPCO 1, , , , , , , SIARELCO 1, , , , , , , SOCOTECO 1 1, , , , , , , SOCOTECO 2 1, , , , , , , SOLECO 1, , , , , , , SORECO 1 2, , , , , , , Final Report Page 148

170 Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Uniform Natgas royalties rebate to all customers DU Revenue Neutral VAT (10.5%) Natgas royalties rebate to Luzon SORECO 2 2, , , , , , , SUKELCO 1, , , , , , , SURSECO 1 1, , , , , , , TARELCO 1 1, , , , , , , TARELCO 2 1, , , , , , , TEI 1, , , , , , , TIELCO 2, , , , , , , VECO 2, , , , , , , ZAMCELCO 1, , , , , , , ZAMECO 1 2, , , , , , , ZAMECO 2 2, , , , , , , ZAMSURECO 1 1, , , , , , , ZAMSURECO 2 1, , , , , , , ZANECO 1, , , , , , , ALL 1, , , , , , , Final Report Page 149

171 Annex III.2.1 Policy Simulation Results I for Commercial Tariff, by DU (in Philippine pesos) DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT ABRECO 31, , , , , , , , AEC 28, , , , , , , , AKELCO 25, , , , , , , , ALECO 24, , , , , , , , ANECO 17, , , , , , , , ASELCO 15, , , , , , , , AURELCO 31, , , , , , , , BATANELCO 24, , , , , , , , BATELEC 1 23, , , , , , , , BATELEC 2 24, , , , , , , , BENECO 22, , , , , , , , BILECO 21, , , , , , , , BLCI 18, , , , , , , , BOHECO 1 24, , , , , , , , BUSECO 16, , , , , , , , CAGELCO 1 22, , , , , , , , CAGELCO 2 24, , , , , , , , CAMELCO 23, , , , , , , , CANORECO 24, , , , , , , , CASURECO 1 31, , , , , , , , CASURECO 2 27, , , , , , , , CASURECO 3 22, , , , , , , , CASURECO 4 29, , , , , , , , CEBECO 1 23, , , , , , , , CEBECO 2 21, , , , , , , , CEBECO 3 22, , , , , , , , CEDC 20, , , , , , , , CELCO 30, , , , , , , , CELCOR 33, , , , , , , , CEPALCO 22, , , , , , , , COLIGHT 21, , , , , , , , COTELCO 17, , , , , , , , DANECO 18, , , , , , , , DASURECO 22, , , , , , , , DECORP 26, , , , , , , , DIELCO 26, , , , , , , , Final Report Page 150

172 DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT DLPC 21, , , , , , , , DORECO 18, , , , , , , , ESAMELCO 23, , , , , , , , FIBECO 18, , , , , , , , FICELCO 30, , , , , , , , FLECO 26, , , , , , , , GUIMELCO 32, , , , , , , , IEEC 23, , , , , , , , IFELCO 31, , , , , , , , ILECO 1 28, , , , , , , , ILECO 2 26, , , , , , , , ILECO 3 25, , , , , , , , ILPI 18, , , , , , , , INEC 25, , , , , , , , ISECO 24, , , , , , , , ISELCO 1 25, , , , , , , , KAELCO 29, , , , , , , , LASURECO 20, , , , , , , , LEYECO 2 20, , , , , , , , LEYECO 3 24, , , , , , , , LEYECO 4 21, , , , , , , , LEYECO 5 21, , , , , , , , LUBELCO 21, , , , , , , , LUECO 25, , , , , , , , LUELCO 32, , , , , , , , MARELCO 28, , , , , , , , MASELCO 22, , , , , , , , MECO 21, , , , , , , , MERALCO 32, , , , , , , , MOELCI 1 19, , , , , , , , MOELCI 2 16, , , , , , , , MOPRECO 29, , , , , , , , MORESCO 2 18, , , , , , , , NEECO 1 23, , , , , , , , NEECO 2 AREA 1 27, , , , , , , , NEECO 2 AREA 2 23, , , , , , , , NOCECO 25, , , , , , , , NORECO 2 27, , , , , , , , Final Report Page 151

173 DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT NORSAMELCO 27, , , , , , , , NUVELCO 27, , , , , , , , OMECO 27, , , , , , , , ORMECO 29, , , , , , , , PANELCO 1 31, , , , , , , , PANELCO 3 25, , , , , , , , PECO 30, , , , , , , , PELCO 1 27, , , , , , , , PELCO 2 25, , , , , , , , PELCO 3 27, , , , , , , , PENELCO 25, , , , , , , , PRESCO 27, , , , , , , , PROSIELCO 31, , , , , , , , QUEZELCO 2 26, , , , , , , , QUIRELCO 26, , , , , , , , ROMELCO 26, , , , , , , , SAJELCO 28, , , , , , , , SAMELCO 1 23, , , , , , , , SAMELCO 2 23, , , , , , , , SFELAPCO 25, , , , , , , , SIARELCO 19, , , , , , , , SOCOTECO 1 14, , , , , , , , SOCOTECO 2 19, , , , , , , , SOLECO 23, , , , , , , , SORECO 1 24, , , , , , , , SORECO 2 30, , , , , , , , SUKELCO 16, , , , , , , , SURSECO 1 20, , , , , , , , TARELCO 1 27, , , , , , , , TARELCO 2 20, , , , , , , , TEI 29, , , , , , , , TIELCO 26, , , , , , , , VECO 30, , , , , , , , ZAMCELCO 15, , , , , , , , ZAMECO 1 29, , , , , , , , ZAMECO 2 29, , , , , , , , ZAMSURECO 1 18, , , , , , , , ZAMSURECO 2 17, , , , , , , , Final Report Page 152

174 DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT ZANECO 16, , , , , , , , All DUs 30, , , , , , , , Final Report Page 153

175 Annex III.2.2 Policy Simulation Results II for Commercial Tariff, by DU (in Philippine peso) Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon Uniform Natgas royalties rebate to all customers DU ABRECO 31, , , , , , , AEC 28, , , , , , , AKELCO 27, , , , , , , ALECO 25, , , , , , , ANECO 17, , , , , , , ASELCO 16, , , , , , , AURELCO 31, , , , , , , BATANELCO 23, , , , , , , BATELEC 1 23, , , , , , , BATELEC 2 25, , , , , , , BENECO 22, , , , , , , BILECO 21, , , , , , , BLCI 19, , , , , , , BOHECO 1 24, , , , , , , BUSECO 16, , , , , , , CAGELCO 1 24, , , , , , , CAGELCO 2 25, , , , , , , CAMELCO 23, , , , , , , CANORECO 25, , , , , , , CASURECO 1 30, , , , , , , CASURECO 2 28, , , , , , , CASURECO 3 23, , , , , , , CASURECO 4 31, , , , , , , CEBECO 1 24, , , , , , , CEBECO 2 21, , , , , , , CEBECO 3 21, , , , , , , CEDC 20, , , , , , , CELCO 30, , , , , , , CELCOR 31, , , , , , , CEPALCO 22, , , , , , , COLIGHT 21, , , , , , , Final Report Page 154

176 Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon Uniform Natgas royalties rebate to all customers DU COTELCO 17, , , , , , , DANECO 17, , , , , , , DASURECO 20, , , , , , , DECORP 26, , , , , , , DIELCO 26, , , , , , , DLPC 22, , , , , , , DORECO 17, , , , , , , ESAMELCO 23, , , , , , , FIBECO 19, , , , , , , FICELCO 30, , , , , , , FLECO 26, , , , , , , GUIMELCO 33, , , , , , , IEEC 25, , , , , , , IFELCO 32, , , , , , , ILECO 1 30, , , , , , , ILECO 2 25, , , , , , , ILECO 3 26, , , , , , , ILPI 18, , , , , , , INEC 24, , , , , , , ISECO 23, , , , , , , ISELCO 1 25, , , , , , , KAELCO 29, , , , , , , LASURECO 19, , , , , , , LEYECO 2 22, , , , , , , LEYECO 3 25, , , , , , , LEYECO 4 22, , , , , , , LEYECO 5 23, , , , , , , LUBELCO 21, , , , , , , LUECO 25, , , , , , , LUELCO 32, , , , , , , MARELCO 28, , , , , , , MASELCO 22, , , , , , , MECO 21, , , , , , , MERALCO 32, , , , , , , Final Report Page 155

177 Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon Uniform Natgas royalties rebate to all customers DU MOELCI 1 20, , , , , , , MOELCI 2 17, , , , , , , MOPRECO 29, , , , , , , MORESCO 2 18, , , , , , , NEECO 1 25, , , , , , , NEECO 2 AREA 1 27, , , , , , , NEECO 2 AREA 2 25, , , , , , , NOCECO 24, , , , , , , NORECO 2 27, , , , , , , NORSAMELCO 28, , , , , , , NUVELCO 27, , , , , , , OMECO 27, , , , , , , ORMECO 29, , , , , , , PANELCO 1 30, , , , , , , PANELCO 3 26, , , , , , , PECO 29, , , , , , , PELCO 1 27, , , , , , , PELCO 2 24, , , , , , , PELCO 3 26, , , , , , , PENELCO 25, , , , , , , PRESCO 27, , , , , , , PROSIELCO 30, , , , , , , QUEZELCO 2 29, , , , , , , QUIRELCO 28, , , , , , , ROMELCO 26, , , , , , , SAJELCO 28, , , , , , , SAMELCO 1 23, , , , , , , SAMELCO 2 24, , , , , , , SFELAPCO 26, , , , , , , SIARELCO 19, , , , , , , SOCOTECO 1 15, , , , , , , SOCOTECO 2 20, , , , , , , SOLECO 24, , , , , , , SORECO 1 25, , , , , , , Final Report Page 156

178 Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon Uniform Natgas royalties rebate to all customers DU SORECO 2 31, , , , , , , SUKELCO 16, , , , , , , SURSECO 1 20, , , , , , , TARELCO 1 26, , , , , , , TARELCO 2 21, , , , , , , TEI 29, , , , , , , TIELCO 26, , , , , , , VECO 30, , , , , , , ZAMCELCO 16, , , , , , , ZAMECO 1 29, , , , , , , ZAMECO 2 29, , , , , , , ZAMSURECO 1 18, , , , , , , ZAMSURECO 2 19, , , , , , , ZANECO 17, , , , , , , All DUs 30, , , , , , , Final Report Page 157

179 Annex III.3.1 Policy Simulation Results I for Low Voltage Industrial Tariff, by DU (in thousand Philippine pesos) DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT ABRECO AEC AKELCO ALECO ASELCO AURELCO BATELEC BATELEC BENECO BUSECO CAGELCO CANORECO CASURECO CASURECO CASURECO CEBECO CEBECO CEBECO CEDC CELCO CELCOR CEPALCO COLIGHT COTELCO DANECO DASURECO DECORP DLPC DORECO ESAMELCO FIBECO FLECO GUIMELCO IEEC IFELCO ILECO Final Report Page 158

180 DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT ILECO ILECO ILPI INEC ISECO ISELCO KAELCO LASURECO LEYECO LEYECO LEYECO LUBELCO LUECO MARELCO MASELCO MECO MERALCO MORESCO NEECO NEECO 2 AREA NOCECO NORECO NORSAMELCO NUVELCO OMECO ORMECO PANELCO PANELCO PECO PELCO PELCO PELCO PENELCO PROSIELCO QUEZELCO QUIRELCO ROMELCO SAJELCO Final Report Page 159

181 DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT SFELAPCO SOCOTECO SOCOTECO SORECO SORECO SUKELCO TARELCO TARELCO TEI TIELCO VECO ZAMCELCO ZAMECO ZAMSURECO ZAMSURECO All DUs Final Report Page 160

182 Annex III.3.2 Policy Simulation Results II for Low Voltage Industrial Tariff, by DU (in thousand Philippine pesos) Revenue Neutral VAT Franchise Tax replacing Proportionate rebate of geothermal Add l rebate to DUs with Natgas royalties rebate to Natgas royalties rebate to Luzon Uniform Natgas royalties to all DU (10.5%) all taxes royalties geothermal BCs MERALCO customers customers ABRECO AEC AKELCO ALECO ASELCO AURELCO BATELEC BATELEC BENECO BUSECO CAGELCO CANORECO CASURECO CASURECO CASURECO CEBECO CEBECO CEBECO CEDC CELCO CELCOR CEPALCO COLIGHT COTELCO DANECO DASURECO DECORP DLPC DORECO ESAMELCO FIBECO Final Report Page 161

183 Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon customers Uniform Natgas royalties to all customers DU FLECO GUIMELCO IEEC IFELCO ILECO ILECO ILECO ILPI INEC ISECO ISELCO KAELCO LASURECO LEYECO LEYECO LEYECO LUBELCO LUECO MARELCO MASELCO MECO MERALCO MORESCO NEECO NEECO 2 AREA NOCECO NORECO NORSAMELCO NUVELCO OMECO ORMECO PANELCO PANELCO PECO Final Report Page 162

184 Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon customers Uniform Natgas royalties to all customers DU PELCO PELCO PELCO PENELCO PROSIELCO QUEZELCO QUIRELCO ROMELCO SAJELCO SFELAPCO SOCOTECO SOCOTECO SORECO SORECO SUKELCO TARELCO TARELCO TEI TIELCO VECO ZAMCELCO ZAMECO ZAMSURECO ZAMSURECO ALL Final Report Page 163

185 Annex III.4.1 Policy Simulation Results I for High Voltage Industrial Tariff, by DU (in thousand Philippine pesos) DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT AEC 1, , , , , , , , ALECO 1, , , , , , , , ANECO 1, , , , , , , , ASELCO 1, , , , , , , , BATELEC 1 1, , , , , , , , BATELEC 2 1, , , , , , , , BOHECO 1 1, , , , , , , , BUSECO 1, , , , , , , , CAGELCO 1 1, , , , , , , , CANORECO 1, , , , , , , , CASURECO 2 1, , , , , , , , CASURECO 4 1, , , , , , , , CEBECO 1 1, , , , , , , , CEBECO 2 1, , , , , , , , CEBECO 3 1, , , , , , , , CEDC 1, , , , , , , , CELCOR 2, , , , , , , , CEPALCO 1, , , , , , , , COLIGHT 1, , , , , , , , DANECO 1, , , , , , , , DECORP 1, , , , , , , , DLPC 1, , , , , , , , DORECO 1, , , , , , , , FIBECO 1, , , , , , , , FLECO 1, , , , , , , , IEEC 1, , , , , , , , ILECO 1 1, , , , , , , , ILECO 2 1, , , , , , , , ILPI 1, , , , , , , , INEC 1, , , , , , , , ISECO 1, , , , , , , , ISELCO 1 2, , , , , , , , KAELCO 1, , , , , , , , LEYECO 2 1, , , , , , , , LEYECO 4 1, , , , , , , , LEYECO 5 1, , , , , , , , Final Report Page 164

186 DU Actual (2011) Base Pre-tax Base Removal of Lifeline Subsidy Elimination of all Subsidies EC Transition RSEC-WR 6% VAT Zero VAT LUECO 1, , , , , , , , LUELCO 2, , , , , , , , MECO 1, , , , , , , , MERALCO 1, , , , , , , , MOELCI 1 1, , , , , , , , MOELCI 2 1, , , , , , , , MORESCO 2 1, , , , , , , , NEECO 1 1, , , , , , , , NEECO 2 AREA 1 1, , , , , , , , NEECO 2 AREA 2 1, , , , , , , , NOCECO 1, , , , , , , , NORECO 2 1, , , , , , , , NUVELCO 1, , , , , , , , PANELCO 1 2, , , , , , , , PANELCO 3 1, , , , , , , , PECO 1, , , , , , , , PELCO 1 1, , , , , , , , PELCO 2 1, , , , , , , , PENELCO 1, , , , , , , , SAJELCO 1, , , , , , , , SAMELCO 1 1, , , , , , , , SFELAPCO 1, , , , , , , , SOCOTECO SOCOTECO 2 1, , , , , , , , SOLECO 1, , , , , , , , SORECO 1 1, , , , , , , , SORECO 2 1, , , , , , , , SURSECO 1 1, , , , , , , , TARELCO 2 1, , , , , , , , TEI 1, , , , , , , , VECO 1, , , , , , , , ZAMCELCO 1, , , , , , , , ZAMECO 1 1, , , , , , , , ZAMECO 2 2, , , , , , , , ZAMSURECO 1 1, , , , , , , , ZANECO 1, , , , , , , , All DUs 1, , , , , , , , Final Report Page 165

187 Annex III.4.2 Policy Simulation Results II for High Voltage Industrial Tariff, by DU (in thousand Philippine pesos) Revenue Neutral VAT Franchise Tax replacing all Proportionate rebate of geothermal Add l rebate to DUs with Natgas royalties rebate to Natgas royalties rebate to Luzon Uniform Natgas royalties rebate DU (10.5%) taxes royalties geothermal BCs MERALCO to all customers AEC 1, , , , , , , ALECO 1, , , , , , , ANECO 1, , , , , , , ASELCO 1, , , , , , , BATELEC 1 1, , , , , , , BATELEC 2 1, , , , , , , BOHECO 1 1, , , , , , , BUSECO 1, , , , , , , CAGELCO 1 1, , , , , , , CANORECO 1, , , , , , , CASURECO 2 1, , , , , , , CASURECO 4 1, , , , , , , CEBECO 1 1, , , , , , , CEBECO 2 1, , , , , , , CEBECO 3 1, , , , , , , CEDC 1, , , , , , , CELCOR 1, , , , , , , CEPALCO 1, , , , , , , COLIGHT 1, , , , , , DANECO 1, , , , , , , DECORP 1, , , , , , , DLPC 1, , , , , , , DORECO 1, , , , , , , FIBECO 1, , , , , , , FLECO 1, , , , , , , IEEC 1, , , , , , , ILECO 1 1, , , , , , , ILECO 2 1, , , , , , , ILPI 1, , , , , , , INEC 1, , , , , , , ISECO 1, , , , , , , Final Report Page 166

188 Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon Uniform Natgas royalties rebate to all customers DU ISELCO 1 2, , , , , , , KAELCO 1, , , , , , , LEYECO 2 1, , , , , , , LEYECO 4 1, , , , , , , LEYECO 5 1, , , , , , , LUECO 1, , , , , , , LUELCO 2, , , , , , , MECO 1, , , , , , , MERALCO 1, , , , , , , MOELCI 1 1, , , , , , , MOELCI 2 1, , , , , , , MORESCO 2 1, , , , , , , NEECO 1 1, , , , , , , NEECO 2 AREA 1 1, , , , , , , NEECO 2 AREA 2 1, , , , , , , NOCECO 1, , , , , , , NORECO 2 1, , , , , , , NUVELCO 1, , , , , , , PANELCO 1 2, , , , , , , PANELCO 3 1, , , , , , , PECO 1, , , , , , , PELCO 1 1, , , , , , , PELCO 2 1, , , , , , , PENELCO 1, , , , , , , SAJELCO 1, , , , , , , SAMELCO 1 1, , , , , , , SFELAPCO 1, , , , , , , SOCOTECO 1 1, SOCOTECO 2 1, , , , , , SOLECO 1, , , , , , , SORECO 1 1, , , , , , , SORECO 2 1, , , , , , , SURSECO 1 1, , , , , , , TARELCO 2 1, , , , , , , Final Report Page 167

189 Revenue Neutral VAT (10.5%) Franchise Tax replacing all taxes Proportionate rebate of geothermal royalties Add l rebate to DUs with geothermal BCs Natgas royalties rebate to MERALCO Natgas royalties rebate to Luzon Uniform Natgas royalties rebate to all customers DU TEI 1, , , , , , , VECO 1, , , , , , , ZAMCELCO 1, , , , , , , ZAMECO 1 1, , , , , , , ZAMECO 2 2, , , , , , , ZAMSURECO 1 1, , , , , , , ZANECO 1, , , , , , All DUs 1, , , , , , , Final Report Page 168