ph electric power industry market and policy assessment

Philippine Electric Power Industry Market and Policy Assessment

and Analysis of International Markets

Prepared by

Prof. Rowaldo D. del Mundo Ms. Edna A. Espos

With Contribution of

Ms. María Isabel Rodríguez González (former State Undersecretary, National Energy Commission of Chile)

UNIVERSITY OF THE PHILIPPINES – NATIONAL ENGINEERING CENTER

and U.P. Engineering Research & Development Foundation, Inc.

May 2011

Philippine Electric Power Industry Market and Policy Assessment and Analysis of International Markets

Final Report

University of the Philippines – National Engineering Center i

Table of Contents Section Title Page No.

EXECUTIVE SUMMARY ........................................................................................................................... 8

I SUPPLY AND DEMAND ANALYSIS OF LUZON GRID ............................................................. 16

1 THE DEMAND SECTOR ................................................................................................................. 17

1.1 SYSTEM DEMAND OF LUZON GRID ................................................................................................. 17 1.1.1 HISTORICAL DEMAND OF LUZON GRID (MW ............................................................................... 17 1.1.2 ELECTRICITY SALES AND CONSUMPTION IN LUZON (2009) ........................................................ 17 1.1.3 DEMAND DRIVERS OF THE LUZON GRID ...................................................................................... 19 1.1.4 LUZON GRID DEMAND FORECAST (2011-2030) ........................................................................ 20 1.2 LOAD CHARACTERISTICS OF THE LUZON GRID ............................................................................. 22

2 THE SUPPLY SECTOR .................................................................................................................... 26

2.1 POWER PLANTS IN LUZON GRID .................................................................................................... 26 2.1.1 INSTALLED AND DEPENDABLE CAPACITY OF POWER PLANTS ..................................................... 26 2.1.2 PROPOSED POWER GENERATION PROJECTS ................................................................................. 27 2.1.3 OWNERSHIP OF POWER PLANTS AND CONTROL OF IPPA CONTRACTED CAPACITY .................... 29 2.2 WHOLESALE ELECTRICITY SPOT MARKET .................................................................................... 31

3 SUPPLY-DEMAND BALANCE ....................................................................................................... 32

3.1 RELIABILITY PERFORMANCE OF THE GRID ................................................................................... 32 3.1.1 RELIABILITY INDEX AND CRITERIA ............................................................................................... 32 3.1.2 HISTORICAL RELIABILITY PERFORMANCE OF LUZON GRID .......................................................... 34 3.1.3 RELIABILITY PERFORMANCE OUTLOOK ........................................................................................ 34 3.2 REGIONAL PERSPECTIVE OF SUPPLY-DEMAND BALANCE ............................................................ 35 3.3 GENERATION EXPANSION ANALYSIS .............................................................................................. 36 3.3.1 GENERATION EXPANSION METHODOLOGY, CRITERIA, AND SCENARIOS ...................................... 36 3.3.2 EXPANSION PATTERN OF LUZON GRID WITHOUT MALAYA AND LIMAY POWER PLANTS ............ 37 3.3.3 EXPANSION PATTERN OF LUZON GRID WITH MALAYA AND LIMAY POWER PLANTS IN-SERVICE 40 3.3.4 HINDSIGHT GENERATION EXPANSION SCENARIO FOR NATURAL GAS PRICE ............................... 42

II ANALYSIS OF THE POLICY AND REGULATORY FRAMEWORK OF THE PHILIPPINE ELECTRIC POWER INDUSTRY ........................................................................................................... 44

4 THE POLICY FRAMEWORK OF THE PHILIPPINE ELECTRIC POWER INDUSTRY ...... 45

5 ASSESSMENT OF RESULTS OF EPIRA REFORMS .................................................................. 50

5.1 TOTAL ELECTRIFICATION ............................................................................................................... 50


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5.2 QUALITY, RELIABILITY AND SECURITY OF ELECTRICITY SUPPLY .............................................. 51 5.3 ENHANCED INFLOW OF PRIVATE CAPITAL, PRIVATE OWNERSHIP AND BROADENING OF THE

OWNERSHIP BASE ...................................................................................................................................... 54 5.3.1 PRIVATIZATION OF NPC ASSETS AND IPP CONTRACTS ............................................................... 54 5.3.2 ENHANCED INFLOW OF PRIVATE CAPITAL.................................................................................... 55 5.3.3 BROADENING OF OWNERSHIP BASE .............................................................................................. 57 5.4 GREATER UTILIZATION OF INDIGENOUS AND NEW AND RENEWABLE ENERGY TO REDUCE

DEPENDENCE ON IMPORTED ENERGY ...................................................................................................... 64 5.5 FAIR AND NON-DISCRIMINATORY TREATMENT OF PUBLIC AND PRIVATE SECTOR ENTITIES IN

THE RESTRUCTURING PROCESS ............................................................................................................... 64 5.6 SOCIALLY AND ENVIRONMENTALLY RESPONSIBLE SOURCES OF ENERGY AND INFRASTRUCTURE

65 5.7 EFFICIENT USE OF ENERGY AND DEMAND SIDE MANAGEMENT .................................................. 66 5.8 AFFORDABLE, TRANSPARENT AND REASONABLE ELECTRICITY RATES ..................................... 67 5.9 CONSUMER PROTECTION AND COMPETITION THROUGH A STRONG AND INDEPENDENT

REGULATOR ................................................................................................................................................ 74

6 ASSESSMENT OF INDUSTRY REGULATION ........................................................................... 75

6.1 STRUCTURAL POLICY ...................................................................................................................... 76 6.1.1 VERTICAL SEPARATION OF TRANSMISSION FROM GENERATION AND DISTRIBUTION ................. 76 6.1.2 VERTICAL INTEGRATION OF GENERATION AND DISTRIBUTION ................................................... 76 6.1.3 HORIZONTAL SEPARATION OF GENERATION ................................................................................ 79 6.2 OWNERSHIP ..................................................................................................................................... 85 6.2.1 PRIVATIZATION OF NPC ASSETS AND IPP CONTRACTS ............................................................... 85 6.2.2 DEMOCRATIZATION ....................................................................................................................... 86 6.2.3 OWNERSHIP OF ELECTRIC COOPERATIVES ................................................................................... 87 6.3 LIBERALIZATION AND DEREGULATION ......................................................................................... 90 6.3.1 GENERATION AND ELECTRICITY MARKETS ................................................................................... 90 6.3.2 STRANDED COSTS .......................................................................................................................... 97 6.4 CONDUCT REGULATION ................................................................................................................ 100 6.4.1 RATE SETTING METHODOLOGY FOR TRANSMISSION AND PRIVATE DISTRIBUTION UTILITIES . 100 6.4.2 NEW RATE SETTING METHODOLOGY FOR ELECTRIC COOPERATIVES ........................................ 102 6.4.3 REGULATION OF NON-PRICE CONDUCT: ERC COMPETITION RULES ......................................... 104 6.5 WHOLESALE ELECTRICITY SPOT MARKET .................................................................................. 106 6.5.1 OVERVIEW OF WESM ................................................................................................................. 106 6.5.2 PERFORMANCE HIGHLIGHTS ....................................................................................................... 109 6.5.3 ASSESSMENT OF WESM .............................................................................................................. 114 6.6 SECURITY OF SUPPLY .................................................................................................................... 120 6.6.1 CAPACITY PLANNING AND PROJECT COMMITMENT .................................................................... 121 6.6.2 PLANNING METHODOLOGY AND CRITERIA ................................................................................. 123 6.6.3 PROVISION OF OPERATING RESERVE .......................................................................................... 125 6.6.4 REPLACEMENT POWER FOR MAINTENANCE OUTAGE ................................................................ 126

7 ASSESSMENT OF INSTITUTIONAL GOVERNANCE FRAMEWORK ................................ 128

7.1 OVERVIEW OF INSTITUTIONAL GOVERNANCE ............................................................................ 128 7.2 APPRAISAL OF INSTITUTIONAL GOVERNANCE ............................................................................ 129 7.2.1 CLARITY OF ROLES AND OBJECTIVES .......................................................................................... 129 7.2.2 AUTONOMY .................................................................................................................................. 131


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7.2.3 PARTICIPATION ............................................................................................................................ 131 7.2.4 ACCOUNTABILITY......................................................................................................................... 132 7.2.5 TRANSPARENCY ........................................................................................................................... 132 7.2.6 PREDICTABILITY .......................................................................................................................... 133

III ANALYSIS OF INTERNATIONAL MARKETS ........................................................................ 134

8 PURPOSE OF ANALYSIS OF COMPARABLE INTERNATIONAL MARKET .................... 135

9 CHILE’S ELECTRIC POWER INDUSTRY ................................................................................. 136

9.1 OVERVIEW OF ELECTRIC POWER INDUSTRY OF CHILE .............................................................. 136 9.2 INDUSTRY RESTRUCTURING AND POLICY REFORMS .................................................................. 140 9.2.1 KEY ISSUES PRIOR TO REFORM ................................................................................................... 140 9.2.2 INSTITUTIONAL BACKGROUND , KEY OBJECTIVES AND ELEMENTS OF THE REFORM ................ 141 9.2.3 POLICY AND REGULATION OF GENERATION ................................................................................ 142 9.2.4 POLICY AND REGULATION OF TRANSMISSION ............................................................................. 149 9.2.5 POLICY AND REGULATION OF DISTRIBUTION .............................................................................. 151 9.3 CHILE’S POST REFORM INSTITUTIONAL GOVERNANCE FRAMEWORK ...................................... 153

10 BRAZIL’S ELECTRIC POWER INDUSTRY ............................................................................ 155

10.1 OVERVIEW OF THE ELECTRIC POWER INDUSTRY OF BRAZIL .................................................. 155 10.2 INDUSTRY RESTRUCTURING AND POLICY REFORM ................................................................. 157 10.2.1 POLICY AND REGULATION OF GENERATION ............................................................................. 161 10.2.2 POLICY AND REGULATION OF TRANSMISSION .......................................................................... 166 10.2.3 POLICY AND REGULATION OF DISTRIBUTION ........................................................................... 169 10.2.4 POLICY AND REGULATION FOR RENEWABLE ENERGY .............................................................. 170 10.3 BRAZIL’S POST REFORM INSTITUTIONAL GOVERNANCE FRAMEWORK ................................. 171

11 KEY POINTS AND LESSONS LEARNED FROM INTERNATIONAL EXPERIENCE ...... 174

12 COMPARATIVE MARKET ANALYSIS: CHILE, BRAZIL AND PHILIPPINES ............... 177

IV PROPOSED REFORMS FOR PHILIPPINE POWER INDUSTRY ....................................... 183

13 POLICY AND REGULATORY REFORMS ............................................................................... 184

13.1 IMMEDIATE REFORMS ................................................................................................................ 184 13.1.1 COMPETITIVE BIDDING OF FORWARD POWER CONTRACTS ....................................................... 184 13.1.2 DEFERMENT OF RETAIL COMPETITION .................................................................................... 184 13.1.3 RESTRUCTURING OF THE OWNERSHIP OF ELECTRIC COOPERATIVES ...................................... 185 13.1.4 LIMITING ERC’S ADJUSTMENT TO INSTALLED GENERATING CAPACITY ................................... 185 13.2 MEDIUM TERM REFORMS .......................................................................................................... 185 13.2.1 PROPER IMPLEMENTATION OF THE PBR RATE-SETTING METHODOLOGY ............................. 185 13.2.2 AMENDMENT OF THE HORIZONTAL SEPARATION POLICY ON GENERATION ........................... 185 13.2.3 INTERCONNECTION OF LUZON, VISAYAS AND MINDANAO ....................................................... 186 13.2.4 STRENGTHENING OF THE WESM ............................................................................................. 186 13.2.5 VERTICAL SEPARATION OF GENERATION AND DISTRIBUTION SECTORS ................................. 186

14 INSTITUTIONAL GOVERNANCE REFORMS ....................................................................... 187


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14.1 DOE’S ASSERTION OF ITS AUTHORITY UNDER EPIRA ........................................................... 187 14.2 STRENGTHENING OF ADMINISTRATIVE CAPACITY OF ERC THROUGH FINANCIAL AUTONOMY

AND MAINTAINING A BALANCE OF EXPERTISE ...................................................................................... 187 14.3 FLEXIBILITY IN THE REGULATORY PROCESSES ........................................................................ 188


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List of Tables Table No. Title Page No.

Table 1. Annual Peak Demand and Growth Rate of Luzon Grid, 2000-2010 ................................ 17 Table 2. Forecasted Annual Peak Demand (in MW) of Luzon Grid, 2011-2030 .......................... 22 Table 3. Plant Cost Parameters for the Screening Curve ....................................................................... 25 Table 4. Load Category of Luzon Grid, 2010 ............................................................................................... 25 Table 5. Generation Capacity in Luzon Grid According to Plant-Type and Regional Location (in MW) ...................................................................................................................................................................... 26 Table 6. Percentage Dependable Capacity by Plant-Type and Regional Location ...................... 27 Table 7. Capacity of Proposed Power Plants for 2010-2017 Published by DOE ......................... 28 Table 8. Proposed Power Plants for 2010-2017 ....................................................................................... 28 Table 9. Private Ownership of Power Plants and Control of IPPA Contracted Capacities ...... 30 Table 10. Reliability Performance of Luzon Grid, 2000-2010 ........................................................... 35 Table 11. Regional Perspective of Power Supply-Demand Balance of Luzon Grid, 2011....... 35 Table 12. Generation Capacity Expansion Without Malaya and Limay Power Plants (Forecast Demand under Moderate Economic Growth Scenario) .................................................... 38 Table 13. Generation Capacity Expansion Without Malaya and Limay Power Plants (Forecast Demand under Low Economic Growth Scenario) ............................................................... 39 Table 14. Generation Capacity Expansion Without Malaya and Limay Power Plants (Forecast Demand under High Economic Growth Scenario) .............................................................. 40 Table 15. Generation Capacity Expansion With Malaya and Limay Power Plants (Forecast Demand under Moderate Economic Growth Scenario) ......................................................................... 41 Table 16. Generation Capacity Expansion With Malaya and Limay Power Plants (Forecast Demand under Low Economic Growth Scenario) .................................................................................... 41 Table 17. Generation Capacity Expansion With Malaya and Limay Power Plants (Forecast Demand under High Economic Growth Scenario) ................................................................................... 42 Table 18. Generation Capcity Expansion for Hindsight Scenario ..................................................... 43 Table 19. EPIRA Policy and Regulatory Framework ............................................................................... 46 Table 20. Addition to Installed Generating Capacity after 2001 ........................................................ 56 Table 21. Committed Generation Investments as of June 2010 ......................................................... 57 Table 22. Ownership Distribution of Private Generating Plants ........................................................ 59 Table 23. CO2 Emission of Selected Philippine Power Plants (in kTons) ...................................... 66 Table 24. MERALCO Comparative Charges1, 20032-20103 (Pesos) .................................................. 71 Table 25. Brazil Average Electricity Prices, 2010 ..................................................................................... 73 Table 26. Installed Generating Capacities of the San Miguel Group in the Luzon Grid ............ 84 Table 27. Installed Generating Capacities of Lopez and Aboitiz Groups in Luzon Grid ........... 84 Table 28. Investments for New Generation Projects in Chile ........................................................... 148 Table 29. Installed Generating Capacity in Brazil (2001-2010) ...................................................... 155 Table 30. Average Price of Electricity in Brazil (2010) ....................................................................... 157 Table 31. Comparative Analysis of Chile, Brazil and Philppine Power Markets ....................... 177


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List of Figures

Figure No. Title Page No.

Figure 1. Luzon Grid Energy Sales (MWh) and Consumption by Sector, 2009 ............................ 18 Figure 2. Luzon Grid Energy Sales by Region, 2009 ................................................................................ 19 Figure 3. Luzon Grid Peak Demand, GRDP, Population and Electricity Price (2000-2010) ... 20 Figure 4. Typical One-Day (Hourly) Demand of Luzon Grid ................................................................ 23 Figure 5. Daily Peak Demand (365 days) of Luzon Grid, 2009 ........................................................... 24 Figure 6. Load Duration and Plant Type Screening Curve .................................................................... 24 Figure Figure 7. Variations in Hydro Power generation ....................................................................... 32 Figure 8. Loss of Load Expectation vs. Capacity Reserve of Luzon Grid, 2000-2010 ................ 33 Figure 10. Reliability Performance of Luzon Grid, 2000-2010 ........................................................... 34 Figure 10. Reliability Performance of Luzon Grid With and Without Expansion ....................... 38 Figure 11. National Gross Power Generation By Resource, 2001 and 2009 ................................. 53 Figure 12. Gross Power Generation By Grid and Resource, 2001 and 2009................................. 53 Figure 13. Weighted Average Price of Malampaya Gas (2002-2009, Quarters) .......................... 54 Figure 14. Control of Installed Generating Capacity as of March 2011 , ........................................ 63 Figure 15. Annual Average Effective Rates Rates (2000-2009) ......................................................... 68 Figure 16. NPC Annual Average Effective Rates (2003-2010) ............................................................ 69 Figure 17. MERALCO Average Monthly Generation Cost (2008-2010) .......................................... 72 Figure 18. Chile: Typical Residential Energy Price .................................................................................. 73 Figure 19. Chile: Typical Industrial Regulated Price ............................................................................... 73 Figure 20. Control of 2010 Installed Generating Capacity, Luzon ..................................................... 85 Figure 21. WESM Governance Structure ................................................................................................... 108 Figure 22. Market Transactions (2009,2010) ......................................................................................... 110 Figure 24. Pricing Errors ................................................................................................................................. 111 Figure 24. Price Substitution ......................................................................................................................... 111 Figure 25. Supply and Demand Profile (26 June 2009 to 25 June 2010) .................................... 112 Figure 26. Monthly Outage Rate By Resource (July 2009-June 2010) .......................................... 112 Figure 27. Price Distribution (June 2009 to June 2010) ..................................................................... 113 Figure 28. Market Price Trend (June 2009 to June 2010) ................................................................. 113 Figure 29. HHI Based on Actual Generation Net of Bilateral ............................................................ 114 Figure 30. Combined Pivotal Supplier-Price Setter Index ................................................................. 114 Figure 31. Generation Capacity Plan of DOE PDP .................................................................................. 124 Figure 32. Governance Structure of the Philippine Electric Power Industry ............................ 128 Figure 33. Energy Production in the Chilean National Grids ............................................................ 138 Figure 34. Generation Profile Per Technology in Chile ....................................................................... 139 Figure 35. Chilean Electricity Market Structure .................................................................................... 140 Figure 36. Percentage Change in Distribution Tariffs From VAD ................................................... 153


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List of Boxes

Box No. Title Page No.

Box No. 1- Forecasting Model for Luzon Grid Peak Demand ............................................................... 20 Box No. 2 - Excerpt, ERC Resolution No. 21 Series of 2005 ............................................................... 93 Box No. 3 - New Rate Setting Methodology for Electric Cooperatives ......................................... 103 Box No. 4 - Excerpt from ERC Competition Rules ................................................................................ 105


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University of the Philippines – National Engineering Center 8

EXECUTIVE SUMMARY1

Objectives of the Study

The paucity of new generation investments despite the EPIRA has led to supply

shortages that conjure unpleasant images of the electricity crisis of the late 1980s to the

early 1990s and increasing calls to amend the law. A number of proposals are now being

considered in and out of Congress – from minor adjustments to drastic overhaul of the

law.

This study is intended to contribute to the debate by offering well-considered proposals

for policy and regulatory reforms to incent generation investments. It is anchored on

the premise that an in-depth analysis of the current state of the industry and its

operating and policy environments are crucial in the design of effective policy and

regulatory responses that could avoid the crisis and the costly IPP route in the 1990s.

Objectives of the Study

The study has several parts. Part I is a market and supply study of the Luzon Grid. Part II

analyzes the policy framework of the Philippine electric power industry, Part III analyzes

the power industry in Brazil and Chile which were chosen as comparators due to their

size and reform’s initial goals. It also includes a set of proposals for policy and regulatory

reforms that were gleaned from the preceding policy analysis. The last part summarizes

the reform proposals for the Philippine Electric Power Industry.

The market analysis of the Luzon Grid aims to establish the opportunities and threats to

new investments in generation capacities. This was achieved by analyzing the demand

and supply sectors, the supply-demand balance situation today and in the future as well

as the network infrastructure for the transmission of electricity in Luzon Grid.

1 This study was prepared by the Energy Advisors of University of the Philippines – National Engineering

Center with funding support from AES. The findings, opinions, conclusions and recommendations are of the authors and not necessarily of the sponsor and UPNEC.


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Part II starts with a brief review of the achievements of the industry vis-à-vis the EPIRA’s

declared policy objectives. This is followed by an analysis of its policy framework as laid

down by the EPIRA and the review of the policies of Brazil and Chile. The analysis is

approached from the perspective of policy and regulatory incentive structure. It seeks to

determine whether a robust incentive structure is provided in the EPIRA, i.e., one that

attract sufficient private investment in generation while achieving its economic

efficiency objectives. Economic efficiency refers to allocate, productive and dynamic

efficiency. The strength of the policy and regulatory incentive structure rests on the

design of the structural policy; liberalization; ownership; conduct regulation; and, the

sequencing of policy reform. In network industries that are naturally monopolistic such

as electricity distribution and transmission, the rules that make up the regulatory

incentive structure act as proxies to the disciplines imposed by a fully competitive

market.

An analysis of international markets was undertaken to enrich the study by providing a

model for the design of policy reform under reasonably comparable circumstances.

Aside from having the longest running and most comprehensive electricity reform after

WWII, Chile’s reforms which started in 1982 are widely acknowledged to be highly

successful and a model for developing countries around the world. Chile has been in the

forefront of innovation in the creation of electricity markets. Brazil on the other hand

has the largest electricity market in South America. These two countries have the

highest access rates in Latin America. While Chile’s electricity system shows that

effective competition and privatization is possible in a relatively small market, Brazil’s

illustrate that it is possible in a large developing market. Their combined experiences

and lessons learned are highly instructive for developing countries like the Philippines

that are still grappling with electricity reforms.

A brief review of the state of industry’s institutional governance is made based on the

results of the policy assessment. Corresponding recommendation to address the gaps in

this area are included in the report.


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To facilitate the timely completion of the study, the impact analysis for policies and

regulations that require historical data was limited to the Luzon grid. The grid accounts

for 74% of the installed generating capacity nationwide and 72% of its total demand.

The current state of generation in the grid is thus a fair indicator of the strengths and

weaknesses of the current policy framework and of the appropriateness of future policy

interventions.

Findings

The salient findings of the assessment of the policy framework and institutional markets are :

1) The objectives of the EPIRA, as listed in its ‘Declaration of Policy’ have not been

achieved;

2) Critical disincentives to generation investments are embedded in inappropriate

policy designs and gaps in the current policy framework coupled with weaknesses

and errors in their implementation ;

3) The sequencing of policy reform in Chile and Brazil prioritized generation adequacy

over market liberalization . In the interim, pro-competitive regulatory mechanisms

primarily, the public auction of long-term power contracts were put in place to

capture the efficiencies of free market competition; and,

4) Weak institutional governance in the Philippine electric power industry arising from

DOE’s inadequate engagement and ERC’s limited administrative capacity.

Recommendation for Reforms

The reform proposals are intended to remedy the weakness of the incentive structure of

the policy, regulatory and governance framework and address the gaps in the

implementation by the regulator of policies that are set-out in the EPIRA. Except for the

amendment to the horizontal policy on generation and on the guarantee authority of

NEA; these proposals will only require executive and regulatory actions to implement.


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The policy and regulatory reform proposals are categorized into immediate (within 6

months) and medium term (from 6 months to 2 years) depending on their urgency and

expected time requirement to implement.

Policy and Regulatory Reforms

a) Immediate Reforms

1 Competitive bidding of forward power contracts

All distribution utilities (PDUs, ECs) should contract for 100% of their energy and

capacity requirements through a competitive public bidding. The utilities (with the prior

endorsement of the ERC and DOE) shall hold yearly public auctions for contracts with a

maximum term of 15 years. Purchases from the spot market shall be limited to 5% of

the DUs’ and generators’ contractual imbalances and shall be subject to the payment of

penalties to be determined by the ERC. Standard contract templates to be drawn up by

ERC and DOE, generators and DUs. Contract quantities shall have priority over spot ones

in case of planned brownouts due to supply shortages (no supply guaranty for

uncontracted energy in case of rationing). A sample contract from the Brazil auction is

attached.

2 Deferment of Retail Competition

Retail competition must be deferred until such time that the vital requirements laid

down in ERC Resolution No. 03, Series of 2007 is achieved:

a) Adequacy of generation, transmission networks , and customer switching systems; and

b) Promulgation by the ERC of all pertinent rules and regulations governing retail

competition and open access. ERC shall determine the timetable with duties and

responsible parties in charge of executing the pending requirements to materialize

RC&OA. Certainty shall be given to the industry in order to allow proper planning.

3 Restructuring of the Ownership of Electric Cooperatives


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ECs may be restructured and consolidated to a small group of equity investors to

strengthen the incentives for productive efficiency. In the interim, the energy

requirements of the ECs should be aggregated by grid and tendered in the auction as

one. Section 30 of the EPIRA shall be amended by Congress to allow NEA to act as

guarantor for the bilateral contract obligations of the ECs, instead of their WESM

purchases.

4 Limiting ERC’s adjustment to installed generating capacity

Adjustment to generating capacity must be limited to permanent derating to avoid the

possible circumvention of the grid limits from the declaration of temporary reductions

in capacity.

b) Medium Term Reforms 1 Proper Implementation of the PBR Rate-Setting Methodology

Proper implementation of the PBR rate-setting methodology for transmission and

private distribution utilities and of the RSEC-WR and proposed PBR for Electric

Cooperatives to improve the utilities’ efficiency and moderate the increases in

electricity rates.

2 Amendment of the Horizontal Separation Policy on Generation

Legislative Amendment of the horizontal separation policy on generation such that the

grid limit is based solely on control of the installed generating capacity. In this regard,

installed generating capacity shall cover IPP capacities whose control were ceded by the

NPC/PSALM to the administrators in the IPPA Agreements.

3 Interconnection of Luzon, Visayas and Mindanao

The Luzon, Visayas and Mindanao grids must be interconnected to mitigate the adverse

effect on energy security of each grid’s high reliance on a single fuel/energy resource.

4 Strengthening of the WESM


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The wholesale spot market must be strengthened to incent new generation investments

by:

a) Reviewing the system operation and network reliability protocols to make them

consistent with consumer valuation;

b) Demand metering to allow consumers to react to changes in the supply and

demand balance;

c) Raising the price cap and sticking to it;

d) Creation of operating reserve, financial hedging, capacity markets and market

for transmission rights to mitigate market risks and solve the ‘missing money’

problem.

5 Vertical Separation of Generation and Distribution Sectors

The generation and distribution sectors must be vertically separated (i.e., remove cross-

ownership) to create robust competition in generation.

Institutional Governance Reforms

The weakness of the institutional governance framework has its roots on: (1) the institutional

paralysis of the DOE; (2) weak administrative capacity of the ERC; and (3) a litigious regulatory

process that does not welcome broad participation and consultations and precludes an effective

appeal mechanism to redress grievances.

1 DOE’s Assertion of its Authority under EPIRA

The DOE must step up into the plate; assert is authority and deliver on its

responsibilities under the law.

2 Strengthening of Administrative Capacity of ERC through Financial Autonomy and

Maintaining a Balance of Expertise

Strengthening the administrative capacity of ERC will require first, financial autonomy

either through an automatic appropriation of its budget or by allowing the agency to


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keep and spend its collections instead of these being remitted to the National Treasury;

and second, maintaining a balance of expertise in the Commission, i.e., finance rather

than accounting (financial policy and strategy is more critical than accounting the

Commission level ); power engineers (not just any engineer); regulatory economists (or

in their absence, micro rather than macro economists); and lawyers. The present

composition of the Commission and its top executive management which is dominated

by lawyers should be restructured to achieve a more balanced composition of these

disciplines. Regulation of infrastructure industries such as the electric power industry is

more about economics rather than law and involves the consideration of the economic,

financial, and technical impact of regulatory decisions rather than on the establishment

and conformity with legal precedents that may be irrelevant to the case on hand. The

current set-up where the Commissioners are appointed by the President need not be

changed. However, the names and the curriculum vitae of candidates should be made

public, e.g., in the newspapers, in the Malacanang and ERC websites so that a public

vetting process takes place before their appointment by the President.

3 Flexibility in the Regulatory Processes

Short of abrogating the quasi-judicial character of the ERC (that will require legislative

amendment); what is required is flexibility in the regulator’s processes that will: (1)

invite broad debate of and meaningful participation by all stakeholders; (2) deepen the

scope of the debate to relevant economic, technical and social issues instead of

confining them to legal procedures and precedents; and (3) provide for an effective

appeal mechanism. On the latter, the ERC could hire more “arbitrators and “conciliators”

akin to those at the National Labor Relations and Conciliation (NLRCC) Board and the

Construction Board rather than requiring all cases to be heard by the Commission and

immediately appealed to the Courts. In addition, a single panel of experts, with a

permanent chair and varying members depending on the issue on hand could be formed

to resolve disputes between the regulator and market agents and among market agents.

The dispute settlement mechanism of WESM, GMC and DMC could be constituted as

sub-groups reporting to this Experts’ Panel when the issues arise from or are within

their jurisdictions.


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I SUPPLY AND DEMAND ANALYSIS OF LUZON GRID


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1 THE DEMAND SECTOR

1.1 SYSTEM DEMAND OF LUZON GRID

1.1.1 HISTORICAL DEMAND OF LUZON GRID (MW

The Annual Peak Demand of the Luzon grid grew at an average annual rate of 3.44%. from

2000-2010 as shown in Table 1. While the first five years (2001-2005) and the second five years

(2006-2010) grew at almost the same pace at 3.40% and 3.47%, respectively , the last five years

showed an increasing trend at 0.36% in 2006 to 8.63% in 2010.

Table 1. Annual Peak Demand and Growth Rate of Luzon Grid, 2000-2010

YEAR Annual GWh

Consumption Growth Rate

Peak MW

Demand Growth Rate

2000 34,679 5,450 - -

2001 38,184 10.11%

3.22%

5,646 3.60%

3.40%

2002 38,387 0.53% 5,823 3.13%

2003 37,535 -2.22% 6,149 5.60%

2004 39,854 6.18% 6,323 2.83%

2005 40,627 1.94% 6,443 1.90%

2006 41,241 1.51%

3.00%

6,466 0.36%

3.47%

2007 43,620 5.77% 6,643 2.74%

2008 44,200 1.33% 6,674 0.47%

2009 44,975 1.75% 7,036 5.42%

2010 48,845 8.60% 7,643 8.63%

Source: 2000-2009 (DOE), 2010 (WESM RTX)

1.1.2 ELECTRICITY SALES AND CONSUMPTION IN LUZON (2009)

The total energy sales and consumption (including own use and system loss) in Luzon account

for 74% of the total Philippines. Visayas and Mindanao has each 13% of the total energy

consumption2.

2 DOE, 2009 Power Statistics


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In Luzon, MERALCO (the single largest distribution utility) accounts for 71% of the total energy

consumption . Its market share (i.e., sales to customers) in 2009 is 61% as shown in Figure 1. The

On-Grid Electric Cooperatives accounts for 11% and another 1% in isolated lated islands which

are served by NPC-SPUG. The Private DUs sales is only 3% while the combined sales to Directly

Connected Customers and Economic Zones is 7%.

Figure 1. Luzon Grid Energy Sales (MWh) and Consumption by Sector, 2009

Figure 2 shows the regional sales of electricity in 2009 to customers of Distribution Utilities (ECs

and PDUs) and to Economic Zones and Directly Connected Customers. Fidty seven percent (57%)

of the total energy sales was delivered to the National Capital Region (NCR). It must noted that

MERALCO’s mega-franchise includes part of Region IV-A (south of NCR) and part of Region III

(north of NCR). Hence, the diffirence between 61% of MERALCO share in the energy sales and

the 57% of energy delivered to NCR accounts for the consumption of the customers in Region III

and Region IV-A.


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Figure 2. Luzon Grid Energy Sales by Region, 2009

1.1.3 DEMAND DRIVERS OF THE LUZON GRID

The grid’s peak demand from 2000 to 2010 is plotted with the gross regional domestic product

(GRDP), population and average price of electricity to end-users in Figure 3.3 Population and

GRDP are strongly correlated with demand at 0.9686 and 0.9582 correlation coefficients,

respectively. Demand has low correlation with end-users price (0.7687 correlation coefficient )

which indicates the inelasticity of demand at the regressed price levels. The regression analysis

of demand with both population and GRDP as drivers did not pass the significance of variable

tests (t-stat and p-value) indicating auto-correlation. Thus, the peak demand of Luzon can be

forecasted either by population or GRDP but not by both population and GRDP in the same

regression equation. The sensitivity of the annual peak demand of Luzon Grid to the maximum

daily temperature of Manila was also analyzed for the months of April to June from 2000 to

2010. The analysis showed that the peak demand during summer season has little correlation

with maximum temperature for the same season. The variations of Manila’s temperature

3 The Gross Regional Domestic Product and population of Luzon were obtained by taking the sum total of

the GRDP (population) of NCR, CAR, Region I, Region II, Region III, Region IV-A, and Region V. The GRDP and population of Region 4B (MIMAROPA) were excluded because the provinces and islands in this sub-region are not connected to the Luzon Grid.


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Box No. 1- Forecasting Model for Luzon Grid Peak Demand

Forecast Model: L = a + b(GRDP) MAPE 2.37%

a 2663.389855 R^2 0.907542262 t-stat 8.861490813

b 4.83671E-06 adj. R^2 0.895985045 p-value 2.07664E-05

throughout the year is not significant in so far as daily peaks are concerned. The temperature

factor is only significant with respect to the hourly load variations.

Figure 3. Luzon Grid Peak Demand, GRDP, Population and Electricity Price (2000-2010)

1.1.4 LUZON GRID DEMAND FORECAST (2011-2030)

Several regression models were formulated to establish the best forecasting model for the

Grid’s annual peak demand. The model selected for this study is shown in Box No. 1 which is a

simple regression equation with GRDP as variable. The model exibited the highest value of

Adjusted R squared (adj. R^2). It is likewise suitable to forecasting a range of possible economic

growth scenarios. This model passed the t-stat criterion ( less than -2 or greater than 2) and p-

value (less than 0.1) for the GRDP regressor. The Mean Absolute Percentage Error (MAPE) of the

model is 2.37% which is lower than the maximum 3% criterion.


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The annual growth rate of the GRDP of Luzon for the period 2000-2010 is 4.88%. The Philippine

GDP growth rate in 2009 was about 1% and in 2010, a hefty 7.3%. Both are aberrations. The

economy was hit hard by the financial crisis in its export markets in 2009 while heavy election

spending in 2010 boosted the economy. With the gradual recovery of the country’s main trading

partners and the added confidence in the country brought about by a change in administration,

the anemic 1% growth is not expected to recur. Thus, the 2010 GRDP was set aside in the

formulation of the forecasting model.

The continued vulnerability of the economy to external shocks and internal structural problems

indicate a prudent approach in estimating future demand. As such, demand is forecasted

under the low, moderate and high economic growth At 3%, 5%, and 7%, respectively. The

demand forecast for 2011 to 2030 in each of these scenarios is shown in Table 2.


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Table 2. Forecasted Annual Peak Demand (in MW) of Luzon Grid, 2011-2030

YEAR Low Economic Growth Moderate Economic Growth High Economic Growth

MW MWh* MW MWh* MW MWh*

2011 7,487 46,742,269 7,581 47,327,033 7,675 47,911,797

2012 7,632 47,645,730 7,827 48,862,040 8,026 50,101,740

2013 7,781 48,576,295 8,085 50,473,797 8,401 52,444,979

2014 7,935 49,534,776 8,356 52,166,142 8,803 54,952,245

2015 8,093 50,522,013 8,641 53,943,104 9,232 57,635,019

2016 8,256 51,538,866 8,940 55,808,914 9,692 60,505,587

2017 8,424 52,586,225 9,254 57,768,015 10,184 63,577,095

2018 8,596 53,665,005 9,583 59,825,070 10,711 66,863,609

2019 8,774 54,776,148 9,929 61,984,979 11,274 70,380,179

2020 8,958 55,920,626 10,292 64,252,883 11,877 74,142,908

2021 9,147 57,099,437 10,674 66,634,182 12,522 78,169,029

2022 9,341 58,313,613 11,074 69,134,546 13,212 82,476,978

2023 9,541 59,564,215 11,495 71,759,929 13,950 87,086,484

2024 9,748 60,852,334 11,936 74,516,580 14,740 92,018,655

2025 9,960 62,179,097 12,400 77,411,064 15,585 97,296,077

2026 10,179 63,545,663 12,887 80,450,272 16,490 102,942,920

2027 10,405 64,953,226 13,398 83,641,441 17,458 108,985,041

2028 10,637 66,403,016 13,935 86,992,168 18,493 115,450,111

2029 10,876 67,896,300 14,498 90,510,431 19,602 122,367,736

2030 11,122 69,434,382 15,090 94,204,608 20,787 129,769,595

* Estimate based on 2009 Load Factor of Luzon Grid (71.26%)

1.2 LOAD CHARACTERISTICS OF THE LUZON GRID

The load characteristic of the grid is also a factor in establishing the most economic mix of

capacity type and energy production of power generation plants. This study used the 2009

Hourly demand of the Luzon Grid obtained from WESM to analyze its load characteristics . The

analysis revealed a 71.26% load factor in 2009.

The typical one-day (hourly) demand is illustrated in Figure 4. The Grid has three peaks

occurring on a typical day: at 11:00AM (morning peak), 2:00PM (afternoon peak), and 7:00PM


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(evening peak). The off-peak demand on a typical day occurs at 4:00AM. From a binomial time-

of-use (TOU) demand point of view, the Grid’s off-peak period is 10:00PM-9:00AM while the

peak period is between 10:00AM and 9:00PM.

Figure 4. Typical One-Day (Hourly) Demand of Luzon Grid

Figure 5 shows the daily peak loads (MW) of the Grid in 2009 . The high peaks occur on

weekdays starting in April and is sustained until September.

In terms of economic dispatch-merit load category, 71.69% of Luzon Grid’s demand is base,

19.08% Intermediate, and 9.23% peaking. The corresponding energy for the load categories are

92.41%, 7.40%, and 0.19%, respectively. These values were obtained from

Figure 6 based on the load duration curve (i.e., the 8760 hourly demand in 2009 arranged in descending order) and plant-type screening curve. The screening curve

was established by plotting the levelized annual generation cost per MW of base load plant (represented by coal thermal power plant), intermediate plant (natural gas combined cycle gas turbine plant) and peaking (diesel) power plant using the plant

cost parameters shown in

Table 3.


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Figure 5. Daily Peak Demand (365 days) of Luzon Grid, 2009

Figure 6. Load Duration and Plant Type Screening Curve

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000

90,000,000

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

PH

P/M

W/Y

R

CAPACITY FACTOR

SCREENING CURVE(Levelized Busbar Cost, PHP/MW/YR)


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Table 3. Plant Cost Parameters for the Screening Curve

The demand in MW, energy in MWh and load factor for the different load categories for the

Luzon Grid in 2010 is shown in

Table 4. The base load is 5,480 MW ; intermediate at 1,458 and peaking at 705 MW. The

combined energy of the intermediate and peaking loads represent only 7.5% of the total energy.

The intermediate load of Luzon Grid can be categorized as peaking load. The slope of the

levelized generation cost of CCGT which was used to represent the intermediate plant in the

screening curve is high due to its fuel price (US$ per MMBTU) which is about twice the fuel price

of coal for base load plant.4 This implies that the dispatch of power plants in the Grid is not

achieving the optimal mix because the CCGT plants in Batangas contracted by NPC and

MERALCO are base loaded (~80% minimum energy off-take) that translate to about 20% instead

of only 7.5% of the total mix.5

Table 4. Load Category of Luzon Grid, 2010

LOAD

CATEGORY DEMAND

(MW) ENERGY (MWH)

Load Factor (%)

Base 5479.633 44,091,582 91.85%

Intermediate 1458.022 3,531,378 27.65%

Peaking 705.346 90,443 1.46%

TOTAL 7643.000 47,713,402 71.26%

4 The fuel price for CCGT was taken from the estimate of the 2010 price of Natural Gas from Malampaya

which is indexed with international fuel oil. 5 Based on the Power Purchase Agreements of NPC with KEPCO and MERALCO with First Gas that was

approved by ERB/ERC

PARAMETER COAL CCGT DIESEL

Capacity (MW) 300 250 100

Plant Cost (US$/KW) $1,800.00 $900.00 $650.00

Fixed O&M (US$/KW-YR) $63.00 $31.50 $22.75

Var O&M (US$/KWH) $0.00500 $0.00300 $0.01000

Fuel Cost (US$/MMBTU) $5.35 $10.81 $13.28

Heat Rate (BTU/KWH) 9,800 7,800 8,500

Fuel Escalation Rate (% p.a.) 1.00% 2.06% 6.00%

Levelizing Period (YRS) 30 30 30

WACC (% p.a.)

Discount Rate (% p.a.)

FOREX (PHP/US$)

15%

12.00%

P45.00


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2 THE SUPPLY SECTOR

2.1 POWER PLANTS IN LUZON GRID

2.1.1 INSTALLED AND DEPENDABLE CAPACITY OF POWER PLANTS

The installed and dependable power generation capacity (in MW) of Power Plants and

Generating Units in the Luzon Grid are summarized according to plant type (fuel and dispatch-

merit) in Table 5. The list includes the currently mothballed 70 MW Hopewell gas turbine plant

with 30 MW dependable capacity and the 242 MW East Asia/Duracom diesel power plant with

dependable capacity of 200 MW. Not included in the list is the 600 MW Sucat oil-fired thermal

power plant which was retired for economic and environmental reasons. The Sucat plant,

however, could be revived in the short-term (i.e., 2-3 years).

Table 5. Generation Capacity in Luzon Grid According to Plant-Type and Regional Location (in MW)

Notes: (1)Dependable Capacity of Wind Power is considered zero

(2) Small Embedded Power Plants not included

Self-Generation facilities are owned and operated by industrial companies such as the 18 MW

gas turbine of Pilipinas Shell Petroleum Corp. in Tabangao, Batangas and the 24 MW extraction

steam turbine of Petron Corp. in Limay, Bataan. Several cement factories have diesel power

plants such as the 20.4 MW of Solid Cement in Antipolo . The ERC granted Certificates of

Compliance to thousands of self-generation facilities in a list that ran to 140 pages. However,

the list contains stanby generating units of commercial and industrial companies which are

Installed MWDependable

MWInstalled MW

Dependable

MWInstalled MW

Dependable

MWInstalled MW

Dependable

MW

Hydro 1505 1225 764 754 2269 1979

Coal 2004 1958 1875 1492 3879 3450

Geothermal 939 431 939 431

Wind+Bio 8.90 0.93 33 0 42 1

Intermediate NG CCGT 2831 2700 2831 2700

Oil Thermal/CCGT 620 600 620 600

Diesel 242 200 491 341 0 0 734 541

GT 70 30 70 30

Total 321 230.93 4654 4124 6408 5376 11383 9731

South Total Luzon

Plant Type

Base

Peaking

Region NCR North


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technically and operationally speaking not self-generation as they are intended for reliability

back-up during outages in the grid.

Table 6 is a matrix of power generation capacity in the Luzon grid by type, location and share of

dependable capacity. Fifty six percent (56%) of dependable capacity are baseload: hydro,

geothermal and coal thermal plants. Natural gas combine cycle plants that are traditionally

considered as intermediate (mid-merit) plants account for 26% of the dependable capacity. The

share of the peaking plants in the capacity mix is 18%. It should be noted that this includes the

Limay oil CCGT plants and Malaya oil fired thermal plants. These plants were inlcuded in the list

of peaking plants due to the price of their fuel although they were originally designed as

intermediate and base load plants.

Table 6. Percentage Dependable Capacity by Plant-Type and Regional Location

Type \ Region NCR North South

Total Luzon

Base 0.01% 32.71% 27.50% 60.22%

Intermediate 0.00% 0.00% 27.75% 27.75%

Peaking 2.36% 9.67% 0.00% 12.03%

Total 2.37% 42.38% 55.25% 100.00%

In terms of location, the capacity in the National Capital Region (NCR) is almost nil (2%) and is

essentially for peaking only. Forty percent (40%) and fifty eight percent (58%) are located in the

North and South of Luzon, respectively.

2.1.2 PROPOSED POWER GENERATION PROJECTS

Commited Projects

The following are committed power generation projects in Luzon:

a) Rehabilitation of 40.8 MW Bac-Man I-2 Geothermal Power Plant in 2012 by

Lopez Group

b) Rehabilitation of 33.55 MW Bac-Man II-1 Geothermal Power Plant in 2013 by

Lopez Group


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c) Commissioning of of new 600 MW Mariveles Coal Thermal Power Plant in

2013 by GNPower

Proposed Projects Published by DOE

The DOE published , through the PDPs, the proposals of the private sector to put up new

capacity in Luzon. However, these are not really committed projects although in many instances

the proponents informed the DOE that they are “committed” (hence the publication). The

proposed projects that were scheduled for commissioning in 2010 to 2017 are summarized in

Table 7 according to plant type.

Table 7. Capacity of Proposed Power Plants for 2010-2017 Published by DOE

Plant Type Generating Capacity

(MW)

Natural Gas 550

Coal 1,775

Geothermal 150

Large Hydro 530

Wind 415

Proposed Projects Published by NGCP

Some serious proposals but no commitment yet were also submitted to NGCP for Grid Impact

Studies. The list of proposed projects are summarized in Table 8 according to commissioning

year. These proposals were used by NGCP in its Transmission Development Plan (TDP) that was

submittted to ERC for approval and inclusion in their PBR rate setting.

Table 8. Proposed Power Plants for 2010-2017

Commissioning Year

No. of Projects

Generating Capacity (MW)

2011 1 105

2012 10 1001

2013 11 1557

2014 6 173

2015 3 500

2016 - -

2017 2 675

2018 1 300


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Source: NGCP

2.1.3 OWNERSHIP OF POWER PLANTS AND CONTROL OF IPPA CONTRACTED

CAPACITY The ownership and control distribution of the combined private installed generating and IPPA

contracted capacities in Luzon Grid are shown inTable 9. There are three dominant players in

Luzon Grid. These are San Miguel Group, the Lopez group and Aboitiz group that owns or

controls 28.13%, 16.33.53% and 17.36%, respectively of the total installed/contracted capacity

of power plants in Luzon. The market is highly concentrated as these three groups control more

than 70% of the generating capacity in Luzon. The share of others including AES, DMCI and

Quezon Power Phils. are less than 7% each.


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Table 9. Private Ownership of Power Plants and Control of IPPA Contracted Capacities

Owner Plant Name Installed

Capacity (MW) %Share of Total

Capacity

A. Lopez Group

1 From Privatized NPC/PNOC Pantabangan-Masiway 112

Bac-Man 150

Total from Privatized

262

2 IPP Plants Sta Rita 1,047

San Lorenzo 549.1

Total IPP Plants

1,596.10

3 IPPA Contracted Capacity

0

Total Lopez Group

1,858.10 16.33%

B. Aboitiz Group

1 From Privatized NPC/PNOC Magat HEPP 360

Tiwi GPP 330

Mak-Ban GPP 410

Ambuklao HEPP 75

Binga HEPP 100

Total from Privatized

1,275

2 IPP Plants

0

3 IPPA Contracted Capacity Pagbilao CFPP 700

Total Aboitiz Group

1,975 17.36%

C. SMC Group

1 From Privatized NPC/PNOC Limay Combined Cycle 655.5

2 IPP Plants

0

3 IPPA Contracted Capacity Sual CFPP 1,000

Ilijan CCGT 1,200

San Roque MHPP 345

Total IPPA

2,545

Total SMC Group

3,201 28.13%

D. AES Masinloc Coal I & II 635 5.58%

E. DMCI Calaca Power Corp 600 5.27%

F. Quezon Power Phil Quezon Power 511 4.49%

G. Other Owners

Angeles Electric Corp Angeles Power Inc 30

Angeles Electric Corp 9

Tarlac Power Corp 18.9

First Cabanatuan Ventures Corp 25.6

Trans-Asia Power Generation Corp 52

Northwind Power Corporation 33

INEC INEC-Agua Grande Mini-HEPP 4.5

SORECO Bicol Hydropower Corp 0.96

Atty Ramon Constancio Cawayan HEPP 448

Barit HEPP 1.8

ISELCO Magat A & B 2.5

Montalban Methane Power Corp 8.19

Phil Power Development Corp MHHP 1.11

Total Other Owners

635.56 5.59%

H. Other IPPAs

Amlan Power Holdings Bakun-Benguet HPP 100.75

Total Other IPPAs

100.75 0.89%

TOTAL PRIVATE

9,516.41 83.63%

TOTAL NPC

1,863.00 16.37%

TOTAL LUZON

11,379.41 100.00%


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2.2 WHOLESALE ELECTRICITY SPOT MARKET

The following excerpts from the assessment report of market results for 2010 show how the

“Big three” of the power industry influence the prices in WESM6:

“Sual CFTPP and Pagbilao CFTPP came out as the two plants with the most number of trading intervals wherein both were setting prices and providing the pivotal supply. There was a significant jump of this measure between 2009 and the first half of 2010. Sual CFTPP was simultaneously setting prices and providing pivotal supply for 7.7% of the time in 2009, and 12.5% of the time in 2010. Likewise, Pagbilao CFTPP was at the same position for 5.5% of the time in 2009, and 13.9% of the time in 2010. This goes to show how critical the market events were during the first half of 2010, especially when prices went up to unprecedented levels.” “The obvious implication is that the potential for market power exercise is higher for plants that are both price setter and pivotal supplier in a trading interval, especially if their exposure in the spot market is also significantly high. This is true if the concerned plants are aware of their advantageous situation and if they have the strategic resolve to exercise those market advantages. The natural gas plants KEPCO Ilijan and Sta. Rita FGPP were also observed to occupy the same advantaged situation although on a lesser extent since a significant portion of their output are contracted.”

“Sual CFTPP is traded by San Miguel Energy Corp. (SMEC) as the Independent Power Producer Administrator (IPPA). The trading participant is fully contracted even if it parlays 48% of its bilateral obligations to the spot market. Pagbilao CFTPP is traded by Therma Luzon Inc. (TLI) with a generating capacity almost equally allocated between the spot market and bilateral contracts market. Even KEPCO Ilijan, traded by PSALM Team 1, has a spot market exposure of 38%. Sta. Rita, owned by First Gas Power Corporation is similarly situated.”

The detailed assessment of WESM is inlcuded in Part 2 (Aanlysis of Policy Framework) of this

Report.

6 From PEMC Report


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3 SUPPLY-DEMAND BALANCE

3.1 RELIABILITY PERFORMANCE OF THE GRID

3.1.1 RELIABILITY INDEX AND CRITERIA

The reliability performance of the generation system, i.,e., the ability of the generation capacity

to meet the demand of the power grid was assessed using probability methods. The reliability

index used to measure the performance of Luzon Grid is the loss-of-load expecation (LOLE)7

because it captures the probabilistic nature of forced outages and its consistency to measure

risks that are associated with variations in capacity, type and number of generating units, the

size of the grid, maintenance of power plants and variations of hydro power generation. Figure

Figure 7 illustrates the variations in hydro power generation in 2009 that was used in the LOLE

calculation. The LOLE is calculated by convolving (i.e., mathematically combining) the

cumulative probability of capacity outages with the demand. In this study, the LOLE of Luzon

Grid was measured in expected number of days in a year (days/year) that there will be a loss of

load. A loss of load will happen if the available generating capacity will not be sufficient to meet

the demand because of the probability of simulataneous outages of generating units of the

power plants.

Figure Figure 7. Variations in Hydro Power generation

7 The power industry has referred to the LOLE as LOLP (loss-of-load probability). Technically

speaking, LOLE is not a probability value but an expected value of probabilistic variable.


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The load of the Luzon Grid was represented by its daily peak. Thus, the loss of load in days/year

does not connote a total system blackout for that number of days in a year. It simply means that

the peak load of some days has a chance of exceeding the remaining capacity after the

simultaneous outages of several units. The criteria used in the assessment of reliability

performance of Luzon Grid is one day per year (1 day/year) loss-of-load expectation.8 The use of

deterministic approach is considered by power system relaibility experts as inconsistent

measure.9

Figure 8 shows the relationship of LOLE and the Reserve of the Grid. It can be deduced that with

the current power plant composition (i.e., type, size and number of generating units) and the

load variation curve (i.e., daily peak loads) of Luzon Grid, the necesary reserve that must be

maintained is about 28.7% to meet the maximum one day per year loss-of-load-expectation.

This is higher than the 20.6% operating reserve (spinning and standby) currently used

(apparently based on PDP published) by DOE.

Figure 8. Loss of Load Expectation vs. Capacity Reserve of Luzon Grid, 2000-2010

8 The 1 day/yr LOLE (or LOLP) was used by NPC as reliability criteria in its power development

planning prior to EPIRA. Based on the PEP published by DOE, it appears that the criteria used now in planning are percentage reserve. 9 Billinton, et.al, “Evaluation of Power System Reliability”, IEEE Press,


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3.1.2 HISTORICAL RELIABILITY PERFORMANCE OF LUZON GRID

The reliability performance i.e., LOLE, of the Luzon Grid from 2000 to 2010 is shown in Figure 9.

The LOLE in 2000 and 2001 were more than 10 days per year but the commissioning of new

power plants in 2002 reduced the LOLE to an acceptable level of not more than 1 day per year. It

is noted however that since no power generation capacity were added after 2006, the growth in

demand led to 4 days/yr LOLE in 2010. This means that in year 2010 the reliability criteria was

violated that translated to rotating interruption since there was not enough operating reserve

capacity to secure the Luzon Grid.

Figure 9. Reliability Performance of Luzon Grid, 2000-2010

3.1.3 RELIABILITY PERFORMANCE OUTLOOK

The outlook for year 2011 to 2014 as shown in

Table 10 is not encouraging inspite of the addition in capacity of the 600 MW Mariveles coal

thermal power plant in 2013. The simulation assumed that the Malaya Oil Thermal Plant is

retired from service. This imply that the Malaya thermal plant should not be retired until new

capacities are added in the system.


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Table 10. Reliability Performance of Luzon Grid, 2000-2010

Year Capacity (MW Demand (MW) Reserve (%) LOLE (Days/Yr)

2011 9583 7581 26.41% 5.07

2012 9624 7827 22.96% 12.08

2013 9657 8085 19.44% 5.27

2014 9657 8356 15.57% 82.27

3.2 REGIONAL PERSPECTIVE OF SUPPLY-DEMAND BALANCE

From the perspective of regional location of loads and power generation capacity, the matrix of

capacity type and dependable capacity margin shown in Table 11 indicates the mismatch of

capacities and demand. This implies that the transmission network must be robust and its

security concerns must be considered even in the design of the market (i.e., a nodal market

design may not be appropriate).

Table 11. Regional Perspective of Power Supply-Demand Balance of Luzon Grid, 2011

Type Dep. Cap

(MW) Demand

(MW) Margin (%)

NCR

Baseload 1 4,914 -99.98%

Intermediate 0 362 -100.00%

Peaking 30 495 -93.94%

Total 31 5,771 -99.46%

North Luzon

Baseload 2,611 1,114 134.46%

Intermediate 600 82 631.12%

Peaking 341 112 203.62%

Total 3,552 1,308 171.56%

South Luzon

Baseload 2,301 427 438.42%

Intermediate 2,700 31 8472.78%

Peaking 0 43 -100.00%

Total 5,001 502 896.30%

Total Luzon

Baseload 4,913 6,455 -23.88%

Intermediate 3,300 476 593.77%


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Peaking 371 651 -43.01%

Total 8,584 7,581 13.23%

3.3 GENERATION EXPANSION ANALYSIS

3.3.1 GENERATION EXPANSION METHODOLOGY, CRITERIA, AND SCENARIOS

The generation expansion analysis was conducted to establish the additional capacity, timing

and type of power plants needed in the Luzon Grid.

The power system models and methodology for the expansion analysis is summarized as

follows:

a) Load Modeling. The 2009 hourly load of Luzon Grid was used as the load pattern for all years of the planning horizon. The load model was obtained by normalizing the 8760 hourly demand by the peak demand in 2009. The load variations is modified by the hydro power generation;

b) Generating Capacity Outage Probability Modeling. The cumulative value of probability of capacity outage is calculated using recursive algorithm;

c) Probabilitic Reliability Evaluation. The LOLE is calculated for a a given annual peak and set of in-service generating units. If the LOLE exceeds 1 day/year in a given year, a generation capacity will be required;

d) Optimal Capacity Mix Evaluation. The generating capacity type (i.e., base, intermediate or peaking) needed is evaluated using the power plant screening curve which consider the investment, fixed and variable O&M, and production (fuel) costs;

e) Optimal Production Simulation. Based on the available power plants capacity (less capacity on maintenance) the load dispatch for each hour of the 8760 hours in a year are simulated based on merit order

f) Generation Cost Calculation. The annuity of the power plant investment, annual fixed and variable O&M, and annual production costs are added and divided by the annual generation of each power plant.

The plant cost chractersitics of the screening curve (Figure 6) in Table 3 was used in establishing

the optimal expansion pattern of Luzon Grid.


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Two (2) scenarios were prepared for the generation expansion analysis relative to the

retirements of existing power plants, particularly of the Malaya and Limay CCGT power plants.

These scenarios were considered because the retirement of the two plants have long been

planned. The study establishes the required expansion pattern with these plants in-service or

out-of-service (i.e., retired). The expansion analysis also pursued three (3) demand growth

scenarios. These are:

a) Moderate economic growth scenario (the GRDP of Luzon will grow 5% annually);

b) Low economic growth scenario (GDRP growth rate of Luzon is 3%); and

c) High economic growth scenario (7% growth rate).

3.3.2 EXPANSION PATTERN OF LUZON GRID WITHOUT MALAYA AND LIMAY POWER

PLANTS

The optimal expansion pattern of Luzon grid with the moderate 5% economic growth driven

demand if Malaya oil thermal and Limay CCGT power plants will be retired is shown in Table 12.

The security of the Grid will be compromised and to meet the reliability criteria of 1 day/year

LOLE, the Grid will require 800 MW of peaking in 2012 and another 900 MW of peaking plants in

2013. The peaking plant requirements is a consequence of the lead time constraints. That is, no

baseload power plant can possibly be commissioned before 2015 if the decision to build will be

made in 2011. The reliability of Luzon Grid generating capacity with and without the expansion

for this scenario is illustrated in Figure 10. The Luzon Grid will require 300 MW of baseload

generating capacities for the years 2015, 2016 and 2017. No intermediate generating capacity

will be needed for the entire planning scenario. This is due to the high price of natural gas in the

country due to its indexation to oil. The economics of power supply implies that the existing

CCGTs in Batangas are more than enough for the next 20 years (assuming that the investment

expansion decision of the generation sector will follow the least cost or optimal mix based on

investment, fixed and variable O&M, and inflating fuel prices).


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Table 12. Generation Capacity Expansion Without Malaya and Limay Power Plants (Forecast Demand under Moderate Economic Growth Scenario)

Figure 10. Reliability Performance of Luzon Grid With and Without Expansion

YEAR BASE INTERMEDIATE PEAKING TOTAL

2011 0 0 0 0

2012 0 0 0 0

2013 600 0 200 800

2014 0 0 900 900

2015 300 0 0 300

2016 300 0 0 300

2017 600 0 0 600

2018 300 0 0 300

2019 300 0 0 300

2020 600 0 0 600

2021 300 0 0 300

2022 600 0 0 600

2023 300 0 0 300

2024 600 0 0 600

2025 300 0 400 700

2026 300 0 200 500

2027 300 0 200 500

2028 600 0 0 600

2029 300 0 300 600

2030 300 0 300 600

TOTAL 6,900 0 2,500 9,400


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Table 13 shows the expansion requirements in the case of a low economic growth scenario (3%

average annual GRDP growth rate) without the Malaya and Limay Power Plants. The peaking

plant requirements in 2012 and 2013 will be 600MW and 700 MW, respectively. This is a

reduction by 200 MW for each year due to the lower demand in this scenario. In addition to

lower capacity requirements to meet the reliability in the immediate scenario, the required

basleoad plants will be 300 MW in 2015 . The next 300 MW will be needed in 2017 instead of

2016 WM.

Table 13. Generation Capacity Expansion Without Malaya and Limay Power Plants

(Forecast Demand under Low Economic Growth Scenario)

On the other hand, if the economic growth of 7% in 2010 is sustained in the future, the Luzon

Grid will require 2,100 MW of peaking plants to ensure the security of the Grid. The base load

capacity addition needed in the Grid, as shown in Table 14, will be 600 MW in 2015 and another

600 MW in 2016.


2011 0 0 0 0

2012 0 0 0 0

2013 600 0 0 600

2014 0 0 700 700

2015 300 0 0 300

2016 0 0 0 0

2017 300 0 0 300

2018 300 0 0 300

2019 0 0 0 0

2020 300 0 0 300

2021 300 0 0 300

2022 300 0 0 300

2023 300 0 0 300

2024 300 0 0 300

2025 300 0 0 300

2026 300 0 0 300

2027 300 0 0 300

2028 300 0 0 300

2029 300 0 0 300

2030 300 0 0 300

TOTAL 4,800 0 700 5,500


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Table 14. Generation Capacity Expansion Without Malaya and Limay Power Plants (Forecast Demand under High Economic Growth Scenario)

3.3.3 EXPANSION PATTERN OF LUZON GRID WITH MALAYA AND LIMAY POWER PLANTS

IN-SERVICE

The previous section indicated the security implications of retiring Malaya and Limay

Plants in the immediate scenario. The optimal expansion patterns of Luzon Grid to meet

day/year LOLE reliability criteria are shown Table 15 to

Table 17.

With moderate demand growth scenario, no additional plants will be required until 2012

provided that rehabilitation of BacMan II-1 unit is completed in 2012 and the maintenance of

power plants are optimally scheduled considering reliability requirements. The grid security

scenario in 2011 and 2012 will be different from 2010 (El Nino year) if the economic growth will

be only a moderate 5%. There is enough intermediate and peaking plants , assuming that the

natural gas CCGTs and diesel plants will be dispatched based on the economic supply mix. The

Luzon Grid will require a total of 7,200 MW of base load plants from 2015 to 2030 if the nat gas


2011 0 0 0 0

2012 0 0 0 0

2013 600 0 500 1,100

2014 0 0 1,000 1,000

2015 600 0 0 600

2016 600 0 0 600

2017 300 0 0 300

2018 600 0 0 600

2019 600 0 0 600

2020 900 0 0 900

2021 600 0 0 600

2022 900 0 0 900

2023 600 0 0 600

2024 900 0 0 900

2025 1,200 0 0 1,200

2026 900 0 0 900

2027 1,200 0 0 1,200

2028 1,200 0 0 1,200

2029 1,200 0 0 1,200

2030 1,200 0 0 1,200

TOTAL 14,100 0 1,500 15,600


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price in the Philippines will continue to be indexed to international Brent oil. In 2015 and 2016,

the Grid will need additional 300 MW each.

Table 15. Generation Capacity Expansion With Malaya and Limay Power Plants (Forecast Demand under Moderate Economic Growth Scenario)

Table 16. Generation Capacity Expansion With Malaya and Limay Power Plants (Forecast

Demand under Low Economic Growth Scenario)


2011 0 0 0 0

2012 0 0 0 0

2013 600 0 0 600

2014 0 0 0 0

2015 300 0 0 300

2016 300 0 0 300

2017 300 0 0 300

2018 300 0 0 300

2019 300 0 0 300

2020 600 0 0 600

2021 600 0 0 600

2022 300 0 0 300

2023 600 0 0 600

2024 300 0 0 300

2025 900 0 0 900

2026 300 0 100 400

2027 300 0 300 600

2028 600 0 0 600

2029 300 250 0 550

2030 300 0 300 600

TOTAL 7,200 250 700 8,150


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Table 17. Generation Capacity Expansion With Malaya and Limay Power Plants (Forecast

Demand under High Economic Growth Scenario)

The low economic growth scenario shown in Table 15 indicates that even the baseload power

plants must be postponed to 2018 (i.e., if the Malaya and Limay Thermal Plants will not be


2011 0 0 0 0

2012 0 0 0 0

2013 600 0 0 600

2014 0 0 0 0

2015 0 0 0 0

2016 0 0 0 0

2017 0 0 0 0

2018 300 0 0 300

2019 0 0 0 0

2020 300 0 0 300

2021 300 0 0 300

2022 300 0 0 300

2023 300 0 0 300

2024 300 0 0 300

2025 300 0 0 300

2026 300 0 0 300

2027 300 0 0 300

2028 300 0 0 300

2029 300 0 0 300

2030 300 0 0 300

TOTAL 4,200 0 0 4,200


2011 0 0 0 0

2012 0 0 0 0

2013 600 0 0 600

2014 0 0 300 300

2015 600 0 0 600

2016 300 0 0 300

2017 600 0 0 600

2018 600 0 0 600

2019 600 0 0 600

2020 900 0 0 900

2021 600 0 0 600

2022 900 0 0 900

2023 600 0 0 600

2024 600 250 0 850

2025 900 250 0 1,150

2026 600 0 300 900

2027 600 250 200 1,050

2028 900 250 0 1,150

2029 600 250 300 1,150

2030 900 250 100 1,250

TOTAL 11,400 1,500 1,200 14,100


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retired). This is the only scenario that shows the condition that should trigger the retirement of

Malaya and Limay plants. In the high economic growth scenario, the Luzon Grid will need 300

MW of peaking plants in 2014 and a minimum of 600 MW baseload plant in 2015.

3.3.4 HINDSIGHT GENERATION EXPANSION SCENARIO FOR NATURAL GAS PRICE

The previous sections has indicated that there will be no adddition of intermediate power plants

(represented by Nat Gas CCGTs). The expansion analysis of this section assumes that the Luzon

Grid is a greenfield in 2011. The 2010 Luzon Grid was assumed to have an optimal mix of base,

intermediate and peaking plants that meets the reliability criteria. The existing renewable

energy-based plants (i.e., hydro and geothermal) are also assumed to be in-service. Table 18

shows how the optimal expansion pattern of base, intermediate and peaking plants will take

place. A series of 600 MW expansion of baseload plants will be followed by a 250 MW of

intermediate. The residual requirements will be provided by peaking plants in 100-300MW

capacity addditions.

Table 18. Generation Capcity Expansion for Hindsight Scenario


2011 0 0 0 0

2012 0 0 100 100

2013 300 0 0 300

2014 300 0 0 300

2015 0 250 0 250

2016 300 0 0 300

2017 300 0 0 300

2018 300 250 0 550

2019 0 0 200 200

2020 300 0 100 400

2021 300 250 0 550

2022 300 0 0 300

2023 300 0 100 400

2024 300 250 0 550

2025 300 0 100 400

2026 300 0 200 500

2027 600 0 0 600

2028 300 250 0 550

2029 300 250 0 550

2030 600 0 0 600

TOTAL 5,400 1,500 800 7,700


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II ANALYSIS OF THE POLICY AND REGULATORY

FRAMEWORK OF THE PHILIPPINE ELECTRIC POWER

INDUSTRY


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4 THE POLICY FRAMEWORK OF THE PHILIPPINE ELECTRIC POWER

INDUSTRY

The policy and regulatory framework of the Philippine electric power industry underwent major

changes over the past twenty-five years. It gained momentum in 2001 when the Government

pushed for extensive reforms through the passage of Republic Act 9136 ‘Electric Power

industry Reform Act’ (EPIRA) . The primary motivations for the reforms were the fiscal deficit

trap created by the contingent liabilities from the IPP take-or-pay contracts that were signed

following the power crisis in the early 1990s and the perceived inefficiencies of the industry.

EPIRA restructured the industry and introduced far-reaching policy and institutional reforms.

Restructuring broke up the National Power Corporation (NPC) into its constituent generation

and transmission components; privatized these assets; established a wholesale power market

and introduced retail competition through a policy of open access to the distribution networks.

The key elements of the policy and regulatory framework created by the EPIRA are

summarized in Table 19.

Institutional reform primarily involved the abolition of the Energy Regulatory Board (ERB) and

the creation, in its place, of the Energy Regulatory Commission (ERC). The ERC, like the ERB is an

independent and quasi-judicial body with broad powers over the industry that revolves around

its exclusive authority to set electricity rates . Its mandate as described in Sec 43 of the EPIRA

are to : (1) promote competition; (2) encourage market development; (3) ensure customer

choice; and (4) penalize abuse of market power.

The responsibility of ensuring the proper implementation of the EPIRA was assigned to the

Department of Energy (DOE). In addition, Section 37 of the EPIRA mandates the DOE to:

a) Ensure the reliability, quality and security of electric power supply;

b) Facilitate/encourage reforms in the structure and operations of distribution utilities;

c) Develop policies and, where appropriate, promote a system of incentives for adequate and reliable electric supply including reserve requirements;

d) Establish the WESM;


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e) Develop policies and programs for energy efficiency;

f) Formulate and implement programs for the development and commercialization of non-conventional energy systems;

g) Encourage private sector investment in the electricity sector; and

h) Promote the development of indigenous and renewable energy sources.10

The DOE Secretary is also directly responsible for total electrification as Chair of the National

Electrification Administration.

Table 19. EPIRA Policy and Regulatory Framework

ISSUE POLICY FRAMEWORK

OWNERSHIP

Privatization of NPC Assets

NPC’s generating , transmission assets and the management and control of the energy output of the IPP contracts are to be privatized according to the guidelines in Sections 47 and 21. NPC prohibited from incurring new obligations to purchase power through bilateral contracts with generation companies or other suppliers.

Transmission Section 45 prohibits generation companies, distribution utilities (DUs) and their subsidiaries or affiliates or stockholder or official and other entities engaged in the generation and supply of electricity within the 4th degree of consanguinity or affinity as specified by the ERC from having direct or indirect interest in TRANSCO or its concessionaire and VICE VERSA. Point-to-point facilities may be developed and owned or operated by a generation company for its exclusive use and for the exclusive purpose of connecting to the transmission system. Ownership of the facilities shall be transferred to TRANSCO at a fair market price in the event that they are required for competitive purposes.

Electric Cooperatives (ECs)

ECs given the option to convert into either (1) stock cooperative under the Cooperatives Development Act or (2) stock corporation under the Corporation Code.

10

EPIRA, Section 37


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Democratization Holdings of persons including directors, officers, stockholders and related interests in a DU (except Electric Cooperatives) and their respective holding companies limited to at most 25% of the voting shares of stocks unless the utility or company holding the shares or its controlling stockholders are already listed in the Philippine Stock Exchange (PSE) , Provided that controlling stockholders of small DUs, i.e. with peak demand of 10 MW or less, who already own the stocks lists in the PSE within 5 years from EPIRA’S enactment. New controlling shareholders to list within 5 years of acquiring ownership and control.

STRUCTURE

Vertical Structure Separation of Transmission and Generation

No explicit policy statement for or against vertical integration of distribution and generation. That integration is allowed may be inferred from Section 45, 6th para, 2nd sentence to wit: “Except as otherwise provided for in this Section, any restriction on ownership and/or control between or within sectors of the electricity industry may be imposed by ERC only insofar as the enforcement of the provisions (i.e., on Cross Ownership, Market Power Abuse and Anti-Competitive Behavior ) of this Section is concerned. Sec 45 limits to at most 50% of total demand that DU can source through bilateral contracts with associated firms except for contracts concluded before the EPIRA

Horizontal Structure As provided in Section 45, no company or related group is allowed to own, operate or control more than 30% of installed generation capacity of a grid and/or 25% of the national installed generating capacity. This restriction does not apply to NPC but applies to IPP Administrators.

LIBERALIZATION

Generation Single buyer arrangement ended . Generation opened to new entrants and de-listed as public utility operation. Franchise requirement lifted.

Wholesale Electricity Spot Market (WESM)

WESM to be established within a year of the law’s effectivity. DUs required to source at least 10% of their demand from WESM in the first 5 years of WESM’s establishment. NEA to act as guarantor of Electric Cooperative’s purchases and for this purpose, its authorized capital stock was increased to PhP 15 Billion.


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Open Access and Retail Competition

Within 3 years (5 years for Electric Cooperatives) of the law’s effectivity subject to:

1) Establishment of the wholesale electricity spot market; 2) Approval of unbundled transmission and distribution wheeling

charges; 3) Initial implementation of cross-subsidy removal scheme; 4) Privatization of at least 70% of total capacity of NPC generating

assets in Luzon and the Visayas; 5) Transfer to IPP Administrators of the management and control of

at least seventy percent (70%) of the total energy output of power plants under contract with NPC

Those with monthly average peak demand during the preceding 12 months of at least 1 MW to be opened to generators and retail electricity suppliers; contiguous areas with aggregate demand of at least 750 kW, 2 years after. A gradual reduction of the threshold until it reaches the household demand level following market evaluation by the ERC.

TRANSITION SUPPLY CONTRACTS (TSC)

NPC to file with ERC TSC negotiated with DUs within 6 months of the law’s effectivity. TSC to contain terms and conditions of supply and rate schedule including applicable adjustments and/or indexation formula. TSC terms shall not extend beyond one (1) year from the declaration of open access.

CONDUCT REGULATION

A. PRICE/RATE REGULATION

Generation Generation and retail supply to contestable market to be deregulated upon implementation of retail competition and open access, except as otherwise provided in the law.

Transmission and Distribution

Regulated . ERC directed to establish and enforce rate-setting methodology for transmission and distribution. It was allowed to adopt appropriate alternative forms of internationally accepted rate setting methodology that results in non-discriminatory and reasonable price of electricity.

B OTHER RATE RELATED POLICIES

Mandated Rate Reduction

NPC rates to residential end-users to be reduced by PhP0.30/kWh upon the law’s effectivity.

Lifeline Rates ERC to set rates for marginalized end-users. These lifeline rates are to be exempted from the phase-out of cross-subsidies.

Cross-Subsidies All cross-subsidies to be phased out within 3 years from the establishment of the universal charge.


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Universal Charge A universal charge on all end users shall be collected within one year of the law’s effectivity for the following purposes:

Payment for the stranded debt of NPC in excess of the PhP 200 Billion to be assumed by the Government;

Payment for the stranded contract costs of NPC and the distribution utilities from contracts approved by the Energy Regulatory Board as of December 31, 2000;

Missionary electrification;

Equalization of taxes and royalties between indigenous and renewable sources of energy and, imported energy fuels as provided in Section 35;

Environmental charge for watershed rehabilitation and management amounting to PhP 0.0025/kwh;

a charge for the removal of cross-subsidies to be imposed for not more than three years.

Stranded Cost To be paid by end-users through the universal charge. This consists of :

(1) NPC Stranded Debt. Any unpaid financial obligation of NPC in excess of the PhP 200 Billion assumed by the National Government.

(2) NPC Stranded Contract Cost. The excess of NPC’s contracted cost of electricity under eligible IPP contracts over their actual selling price in the market. To be eligible, contracts should have been approved by the ERC by December 31, 2000.

(3) DU Stranded Contract Cost. The excess of the DU’s contracted cost of electricity under eligible contracts over the actual selling price of such contracts in the market. . To be eligible, contracts should have been approved by the ERC by December 31, 2000.

C NON-PRICE CONDUCT

General Prohibitions Section 44 of the law prohibits any person or participant in the electric power industry from engaging in anti-competitive behavior including but not limited to cross-subsidization, price or market manipulation, or other unfair trade practices

Competition Rules ERC directed to promulgate competition rules within one year of the law’s effectivity. The rules are intended to ensure and promote competition, encourage market development and customer choice and discourage/penalize abuse of market power, cartelization and any anti-competitive or discriminatory behavior.


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5 ASSESSMENT OF RESULTS OF EPIRA REFORMS

Whether the law has been effective is best examined by comparing the achievements to date

with its objectives. Section 2 ‘Declaration of Policy’ of the EPIRA recites the State’s policy

objectives. These are summarized below to wit:

a) Total electrification;

b) Quality, reliability and security of electricity supply;

c) Enhanced inflow of private capital , private ownership and broadening of ownership base;

d) Fair and non-discriminatory treatment of public and private sector entities in the restructuring process;

e) Socially and environmentally compatible energy sources and infrastructure;

f) Greater utilization of indigenous and new and renewable energy to reduce dependence on imported energy;

g) Efficient use of energy and demand side management;

h) Affordable, transparent and reasonable electricity rates; and

i) Consumer protection and competition through a strong and independent regulator.

5.1 TOTAL ELECTRIFICATION

The DOE targets 100% electrification of barangays by 2008 and 90% of households by 2017.11

Recent DOE statistics report that 99.4% of barangays had been electrified by 200912. The

electrification levels by grid were 99.66 %, 99.53% , 99.67% in Luzon, Visayas and Mindanao

respectively.

The accuracy of this data was challenged during the deliberation of the DOE budget at the

House of Representatives in September 2010.13 A subsequent briefing by NEA to the House’

Committee on Energy on November 2010 confirmed the inaccuracy of the official DOE/NEA

11

DOE Expanded Rural Electrification Program, www.doe.gov.ph 12

Ibid, Power Statistics 13

Philippine Daily Inquirer


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electrification data.14 NEA reported that 31% of the 100,186 sitios nationwide are still not

electrified and set a 100% energization target by 2020.

Neither the DOE nor NEA publish data on the level of household electrification.

5.2 QUALITY, RELIABILITY AND SECURITY OF ELECTRICITY SUPPLY

DOE does not have a working plan or program that will directly address the quality and

reliability of electricity supply. It appears to have left this responsibility to the ERC. ERC has set

systems loss targets but not those of other reliability and service quality indices in the Grid and

Distribution codes. Instead , the latter are merely nominated by distribution utilities and NGCP

whose rates are determined under the Performance Based Regulation (PBR) rate-setting

methodology, based on their performance in the last three years.

While many distribution utilities made significant reduction in systems losses, power losses as a

percentage of total electricity consumption stayed at 12% in 2001 and 2009.15 A thorough

assessment of the EPIRA’s achievements vis-à-vis energy security, reliability and quality is made

in Section 3.6 that shows serious deficiencies in DOE’s planning process.

To ensure energy security, the Department will:16

a) Accelerate the exploration and development of oil, gas and coal resources;

b) Intensify development and utilization of renewable and environment-friendly alternative energy resources/technologies;

c) Enhance energy efficiency and conservation;

d) Attain nationwide electrification;

e) Put in place long-term reliable power supply;

f) Improve transmission and distribution systems;

14

NEA „Briefing for the Committee on Energy‟, November 4, 2010 15

DOE Power Statistics 16

DOE „Philippine Energy Plan‟ 2009-2030


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g) Secure vital energy infrastructure and facilities; and

h) Maintain a competitive energy investment climate.

Apart from the methodologies described in Section 3.6; security of energy supply is also

affected by: (1) fuel diversity , and (2) import dependency. 17 Higher fuel diversity leads to

higher supply security. The risk of supply disruption and price volatility is directly related to the

level of import dependency especially on oil and gas and lately also coal; fuels that have the

greatest price volatility.

Another important indicator is energy efficiency which is measured by energy intensity, i.e.

energy consumption per unit of GDP. These three indicators directly correspond with programs

1 to 3 above.

The national picture however hides the fragile state of the country’s energy security relative to

power generation. This is largely due to the dominance of a single fuel at the grid level and a

pricing policy on key indigenous energy resources that exposes much of power generation to

the volatility of the international price of oil and coal. Figure 11 and Figure 12 reveal over-

reliance in each grid on single resource , i.e., Luzon on natural gas; Visayas on geothermal steam

and Mindanao on hydro resources. Just this year, acute power shortages were experienced in

the Visayas and Mindanao grids when the old geothermal plants in the former had to shut down

for rehabilitation and hydrothermal plants in the latter, due to prolonged drought. The condition

was somewhat eased in the Visayas by the 440 MW HVDC transmission line between Leyte and

Luzon that allowed for limited imports . Mindanao, which is isolated , did not get a similar

reprieve.

17

World Bank “Winds of Change: East Asia‟s Sustainable Energy Future‟ May 2010


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Figure 11. National Gross Power Generation By Resource, 2001 and 2009

Figure 12. Gross Power Generation By Grid and Resource, 2001 and 2009

The price of Natural gas from Malampaya is indexed to the international oil price while that of

geothermal steam from all the steam fields previously held by PNOC-EDC , to the international

price of coal. Consequently, the domestic price of natural gas has followed the trend of, and

had not been spared from the volatility of international oil prices as shown in Figure 13. In a

departure from the past contracts between NPC and PNOC-EDC that indexed the steam price to

0

10000

20000

30000

40000

50000

2002 2009 2002 2009 2002 2009

GW

h

Year

Coal Oil-Based Natural Gas Geothermal

Hydro Wind Biomass

Luzo Visayas Mindanao


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domestic inflation only, the steam sales contract in 2006 between PSALM and PNOC-EDC

indexed the steam price to the international price of coal as well. This indexation could be

behind the nearly 50% increase in steam cost, from PhP 1.7-1.9/kWh in 2008 to PhP

2.8328/kWh in 2009 that the new owners of the Visayas geothermal plants want to recover

from customers in the Visayas Grid.

Source: DOE

Figure 13. Weighted Average Price of Malampaya Gas (2002-2009, Quarters)

5.3 ENHANCED INFLOW OF PRIVATE CAPITAL, PRIVATE OWNERSHIP AND

BROADENING OF THE OWNERSHIP BASE

5.3.1 PRIVATIZATION OF NPC ASSETS AND IPP CONTRACTS

Privatization proceeded at a very slow pace and was hobbled by many issues such as pricing,

and difficulty in securing the agreement of creditors for the transfer of liabilities from NPC to

PSALM. The operation of the transmission assets was finally awarded in 2008 to a private

concessionaire after three failed biddings. Sale of the generation assets only gained momentum

in 2008-2009 and and is now practically complete at 82.6% of total capacity (based on PSALM

plant capacity records; 89% based on ERC plant capacity reports) of total capacity while 80.21

02468

101214

0 4 8 12 16 20 24 28 32 36

Pri

ce (

US$

)

Quarter

US$/GJ US$/MMBTU


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% of the energy output (76.85% based on ERC plant capacity records) 18 of the IPPs have been

transferred to private administrators. Privatization of the remaining IPPs has been derailed by

cases filed in the Supreme Court questioning their Constitutionality and/or consistency with the

policy objectives and guidelines of the EPIRA.

5.3.2 ENHANCED INFLOW OF PRIVATE CAPITAL

New investments in generation by private investors were less than a trickle. The installed generating capacity as of April 2010 was 15,607.8 MW, a mere 2,222.8

increase from 13,385 MW in 2001.19 Of these new investments , 3,780 MW were in 139.1 MW in the Visayas and 265 in MW20. As shown in

Table 20, except for Northwind Power and Montalban LFG which are driven by renewable

energy policy and program of the givernment, those in Luzon were already committed prior to

the EPIRA.

Committed generation investments as of July 2010 as recorded by the DOE were 600 MW in

Luzon, 671 MW in the Visayas and 100.50 MW in Mindanao as shown in Table 21. Their target

completion dates are from March 2010 (for the expansion of Unit I of the CFB Power Plant) to

July 2014 (for the Mindanao 3 Geothermal Power Plant).

Except for a few distribution utilities of local government units, distribution utilities including

the Electric Cooperatives had long been privately owned by the time of the enactment of the

EPIRA. The privatization of Olongapo’s public distribution utility in 2010 completed the

privatization of this sector.

18

The variation in plant capacity records of PSALM and ERC stems from ERC‟s adjustments in installed capacity limit from temporary causes such as outages. On the other hand, there is no baseline record for energy output per se. The baselines used by PSALM/JCPC are a combination of contracted capacities in PPAs and dependable capacities). 19

DOE Power Statistics 2010 20

The discrepancy between the 2010 installed generating capacity and aggregate new investments between 2001-2010 is due to the decommissioning of the Bataan , Manila, Sucat Thermal Power Plants; Cebu II, Aplaya and General Santos Diesel Plants with a combined installed capacity of 1,459.3 MW


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The transfer of the operation of the transmission system to a private concessionaire is expected

to enhance the inflow of private capital for rehabilitation and expansion of the network.

Table 20. Addition to Installed Generating Capacity after 2001

Plant Type Plant Name Owner Installed Capacity

(MW)

Date Commissioned

Luzon

Coal Asia Pacific Energy Corp Non-NPC/IPP 50 2006

Natural Gas Sta Rita Non-NPC/IPP 1,060 Jun 2000/Oct 2011

Natural Gas Ilijan Non-NPC/IPP 1,271 Jun 2002

Natural Gas San Lorenzo Non-NPC/IPP 500 Sept 2002

Hydro San Roque Non-NPC/IPP 345 May 2003

Hydro Kalayaan 3 & 4 NPC-IPP 355 May 2004

Hydro Casecnan Non-NPC/IPP 165 Apr 2002

Hydro Cawayan Non-NPC/IPP .40 Jun 2002

Wind Northwind Power Non-NPC/IPP 33 Jun 2005

Biomass Montalban LFG Non-NPC/IPP 1.0 Jun 2009

Total Luzon 3,780

Visayas

Bunker Fuel Global Business Power Corp (Iloilo)

Non-NPC/IPP 20 Feb 2006

Bunker Fuel Global Business Power Corp (Aklan)

Non-NPC/IPP 12.5 Aug 2006

Bunker Fuel Global Business Power Corp (Aklan)

Non-NPC/IPP 5 Sept 2006

Diesel Guimaras Power Project Trans-Asia 3.4 Apr 2005

Diesel PDPP III (Pinamucan) SPC Power Corp

Non-NPC/IPP 66.4 Transferred 2005

Biomass San Carlos Bioenergy Bronzeaok Phil Inc

8.3 Feb 2009

Biomass First Farmers Biomass Cogen

Non-NPC/IPP 21 Feb 2009

Hydro Sevilla Hydroelectric Plant Non-NPC/IPP 2.5 Nov 2008

Total Visayas

139.1

Mindanao

Diesel PB 104 NPC 32 Sept 2005

Solar Sitio Lomboy, Cagayan Non-NPC/IPP 1 Sept 2004

Coal Mindanao Coal I & II NPC-IPP 232 Sept & Nov 2006

Total Mindanao

265

Source: DOE Power Statistics 2010


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Table 21. Committed Generation Investments as of June 2010

Project Proponent Capacity

(MW) Target Completion

Luzon

2 x 300 MW Coal Fired Power Plant

GN Power 600 4th quarter 2012

Total Luzon 600

Visayas

3 x 82 MW CFB Power Plant Expansion Project

Cebu Energy Development Corp

246 Unit I March 2010 Unit II June 2010 Unit III Jan 2011

Cebu Coal Fired Power Plant KEPCO SPC Power Corp

200 Unit I Feb 2011 Unit II May 2011

2 x 17.5 MW Panay Biomass Power Project

Green Power Panay Phil

35 Unit I 2011 Unit II 2012

Nasulo Geothermal EDC 20 2011

2 x 82 MW CFB Power Plant Panay Energy Development Corp

164 Unit I Sept 2010 Unit II Dec 2010

Total Visayas 671

Mindanao

Sibulan Hydroelectric Power Hedcor Sibulan, Inc 42.5 June 2010

Cabulig Mini-Hydro Power Plant Mindanao Energy Systems Inc

8 June 2011

Mindanao 3 Geothermal EDC 50 July 2014

Total Mindanao 100.50

TOTAL COMMITTED INVESTMENTS

1,317.5

Source: DOE, 16th EPIRA Implementation Status Report (Period covering November 2009-April 2010)

5.3.3 BROADENING OF OWNERSHIP BASE

Generation

Broadening of the ownership base is subject to the installed capacity limits in Section 45(a) of

the EPIRA. The law prohibits the ownership, operation or control by a company or related group

of more than thirty percent (30%) of the installed generating capacity in a grid and/or twenty-

five percent (25%) of the national installed generating capacity. The NPC is exempt from this

prohibition.

Data from the DOE and ERC show that while NPC’s ownership went down from 74% in 2003 to

51.8% in 2010, the government through the NPC owned plants and IPPs retains majority


Final Report


ownership of the country’s installed generating capacity in 2010. On a grid basis, government

ownership in 2010 is highest in Mindanao at 85.6% followed by Luzon and Visayas at 53% and 14%

respectively.

The decline in government ownership is primarily due to the sale of NPC owned plants. The

ownership distribution of the private generating capacities, i.e. those not under contract with

NPC are shown in Table 22.

Control of the output of the installed generating capacities remains largely with the NPC except

in Luzon as shown in Figure 14. The San Miguel group now holds nearly 30% (or slightly over 30%

depending on the accuracy of the ERC or DOE data on installed capacities) from its acquisition of

NPC owned plants and administration of the IPP outputs that were transferred to it from PSALM

under the IPP Agreements (IPPA).

Transmission

Broadening of the ownership base of the transmission utility would have been possible by

selling the three grids to three different parties. While the EPIRA does not preclude this option;

the operation of the national network was transferred in 2008 as a whole to a single party on a

concession basis only.

Distribution

Broadening the ownership base of distribution could have been effected by the juridical

separation and sale to different entities of the distribution networks owned by MERALCO but

which had their own franchises prior to the EPIRA. Instead Congress passed a law in 2004

consolidating these franchises into a MERALCO mega-franchise.

Rather than broadening their ownership base, some of the 109 Electric Cooperatives 21may

have to merge to achieve operating efficiency. While DOE has considered this option, it has

proven to be politically difficult to implement.

21

As of end 2010, 10 on-grid ECs , 9 of which are in Luzon had registered with the Cooperative Development Authority. These are Pangasinan I, Pangasinan III, Isabela II, Nueva Vizcaya,


Final Report


Table 22. Ownership Distribution of Private Generating Plants

Owner Plant Name Installed Capacity

(MW)

% Share of Total Private

Luzon

A. Lopez Group

1 From Privatized NPC/PNOC Pantabangan-Masiway 112

Bac-Man 150

Total from Privatized 262

2 Others Sta Rita 1,047

San Lorenzo 549.1

Total Others 1,596.10

Total Lopez Group 1,858.10 32.47%

B. Aboitiz Group

1 From Privatized NPC/PNOC Magat HEPP 360

Tiwi GPP 330

Mak-Ban GPP 410

Ambuklao HEPP 75

Binga HEPP 100

Total from Privatized 1,275

2 Others 0

Total Aboitiz Group 1,275 22.28%

C. San Miguel Group Limay Combined Cycle 655.5 11.45%

D. AES Masinloc Coal I & II 635 11.10%

E. DMCI Calaca Power Corp 600 10.48%

F. Quezon Power Phil Quezon Power 511 8.93%

G. Other Owners

Angeles Electric Corp Angeles Power Inc 30

Angeles Electric Corp 9

Tarlac Power Corp 18.9

First Cabanatuan Ventures Corp 25.6

Trans-Asia Power Generation Corp

52

Northwind Power Corporation 33

INEC INEC-Agua Grande Mini-HEPP 4.5

SORECO Bicol Hydropower Corp 0.96

Atty Ramon Constancio Cawayan HEPP 0.448

Barit HEPP 1.8

ISELCO Magat A & B 2.5

MOntalban Methane Power Corp 8.19

Phil Power Development Corp 1.11

Total Other Owners, Luzon 188.008 3.29%

Quirino, Abra, San Jose City, Palawan, Sorsogon II, Negros Occidental. None has converted into Stock Corporations


Final Report


TOTAL PRIVATE , LUZON 5,722.61 100.00%

Transmission

Broadening of the ownership base of the transmission utility would have been possible by

selling the three grids to three different parties. While the EPIRA does not preclude this option;

the operation of the national network was transferred in 2008 as a whole to a single party on a

concession basis only.

Distribution





Rather than broadening their ownership base, some of the 109 Electric Cooperatives may have

to merge to achieve operating efficiency. While DOE has considered this option, it has proven to

be politically difficult to implement.


Final Report


Table 22. Ownership Distribution of Private Generating Plants (cont.)


(MW)


Visayas

A. Lopez Group

1 From Privatized NPC/PNOC Tongonan I, Palinpinon I & II 305

Unified Leyte 618.4

Northern Negros GPP 49.37

Total from Privatized 972.77

2 Others 0

Total Lopez Group 972.77 54.44%

B. Aboitiz Group

1 From Privatized NPC/PNOC 0

2 Others Cebu Private Power Corp 73

East Asia Limited Corp 50

Total Aboitiz Group 123 6.88%

C Global Business Power Corp

1 From Privatized 0

2 Others Panay Power Corp 108

Cebu Energy Development Corp 167.4

Panay Energy Development Corp

82

Toledo Power Corp 134.75

Total Global Business Power Corp

492.15 27.54%

D Other Owners

SPC Power Corp Bohol DPP, Panay I & II 166.5

BOHECO I Janopol HEPP/Sevilla HEPP 7.5

SAMELCO I Ton-ok Mini HEPP 1

CEBECO I Mantayupan, Matutinao, Basa 1.7

Sta Clara International Corp Loboc HEPP 1.2

SOLECO Henabian MHPP 0.8

Bronzeoak Philippines Inc San Carlos Bioenergy Co, Inc 8.3

ICS Renewables Amlan HEPP 0.8

Enervantage Suppliers Co, Inc Enervantage Bunker C-Fired DPP

11

Total Other Owners, Visayas 198.8 11.13%

TOTAL PRIVATE, VISAYAS 1,786.72 100.00%


Final Report


Transmission

Broadening of the ownership base of the transmission utility would have been possible by selling the three grids to three different parties. While the EPIRA does not preclude this option; the operation of the national network was transferred in 2008 as a whole to a single party on a concession basis only.

Distribution





Rather than broadening their ownership base, some of the 109 Electric Cooperatives may have

to merge to achieve operating efficiency. While DOE has considered this option, it has proven to

be politically difficult to implement.


Final Report


Table 22. Ownership Distribution of Private Generating Plants (cont.)


(MW)


Mindanao

A. Lopez Group

1 From Privatized NPC/PNOC Mindanao I & II Geothermal Partnership

108.5

Bukidnon Power Corp 1.8


2 Others 0

Total Lopez Group 110.3 24.63%

B. Aboitiz Group

1 From Privatized NPC/PNOC Talomo MHEPP 4.6

Power Barge 117 100

Power Barge 118 100


2 Others DALIGHT Bajada Power Plant 53.5

Cotabato Light & Power Co 9.9

Sibulan A & B 42.59

Total Others 105.99

Total Aboitiz Group 310.59 69.37%

C. CEPALCO Mindanao Energy Systems, Inc 18.9

Bubunuwan Power Co, Inc 7

Solar Photovoltaic 0.95

Total CEPALCO 26.85 6.00%

TOTAL PRIVATE, MINDANAO 447.74 100.00%

Source: Plant name and installed capacity were based on ERC Resolution No 20 Series of 2010 „A Resolution Setting the Installed Generating Capacity Per Grid, National Grid and the Market Share Limitations Per Grid and the National Grid for 2010‟ issued on October 5, 2010. Information on plant ownership partly sourced from DOE 2009 Power Statistics


Final Report


Source: ERC and DOE Data

Figure 14. Control of Installed Generating Capacity as of March 2011 ,

Luzon, Visayas and Mindanao

San Miguel

30%Lopez15%

Aboitiz17%

NPC16%

Others22%

Control of Installed Capacity, Luzon

NPC41%

Lopez Group17%

Aboitiz14%

Global Business

Power17%

SPC8%

Others 3%

Control of Installed Capacity, Visayas

NPC83%

CEPALCO1%

Aboitiz16%

Control of Installed Capacity, Mindanao


Final Report


5.4 GREATER UTILIZATION OF INDIGENOUS AND NEW AND RENEWABLE ENERGY TO

REDUCE DEPENDENCE ON IMPORTED ENERGY

The reduction in the share of imported energy in the generation mix was mainly due to the

discovery and utilization of natural gas from Malampaya whose share of gross generation

jumped to 32.1% in 2009 from 1.8% in 2001. However, the boost to energy security that could

have resulted from this development was undermined by the indexation of its price to the

international price of Brent oil.

DOE targets the doubling of renewable capacity by 2030. From the results so far, it looks like

only hydro is on track to meet this objective. The contribution of new renewable energy to the

generation mix barely moved: from 0 in 2001 to 64 MW in 2009. Of the ‘old’ renewable energy,

hydro increased by 58% from 3,518 MW in 2001 to 3,291 MW in 2009 while generation from

geothermal was practically maintained: at 1,931 MW in 2001 and at 1,953 in 2009. That said,

the inordinate focus by the government on renewable energy to the point of loading all possible

incentives for investments in the sector is unnecessary and may turn out to be both counter-

productive and financially unsustainable. Hydro and geothermal already account for 33% of

gross generation while natural gas, a clean resource adds another 31% or a total of 64%. In

comparison, countries in Europe that pioneered the adoption of Feed-in-Tariffs (FIT) such as

Germany, Spain and France started with less than 5% RE contribution in their generation mix. As

it is, they have scaled back their FIT while maintaining their 20% RE target for 2020. Massive

fiscal and policy incentives risk the commercialization of renewable resources and technologies

in the Philippines that are on the fringe and could potentially undermine the reliability of the

country’s energy supply. At the same time, fiscal incentives such as tax exemptions strains the

government finances and are thus unsustainable in the long-run.

5.5 FAIR AND NON-DISCRIMINATORY TREATMENT OF PUBLIC AND PRIVATE SECTOR

ENTITIES IN THE RESTRUCTURING PROCESS

No report of discrimination reported.


Final Report


5.6 SOCIALLY AND ENVIRONMENTALLY RESPONSIBLE SOURCES OF ENERGY AND

INFRASTRUCTURE

A target of 32,000 Gigagrams (32 Metric Tons) cumulative emission avoidance of carbon dioxide

was set in the Philippine Energy Plan (PEP) for 2004-2013. To achieve this, the DOE planned to:

a) aggressively promote Renewable Energy;

b) prioritize the conversion of old and retiring oil and coal-fired power plants to natural gas;

c) strictly implement the fuel quality standards in the Philippine Clean Air Act; and

d) implement energy efficiency and conservation measures.

There is no indication from either the various DOE reports or the DENR on the cumulative

avoided emission performance to date vis-à-vis the target.

Power Generation is a close second to Transport in CO2 emissions. The Philippine National

Communication to the UN Framework Convention on Climate Change disclosed that of the Total

CO2 emission of 50,038 kilo-ton of the energy sector in 1994, 15,888 or 31.7% was from

Transport and 15,508 or 31% from Power Generation. The Carbon Monitoring for Action

(CARMA), estimated the CO2 emission of all Philippine power plants, i.e. grid and off-grid

including embedded plants of industries, at 24,425,721 kTons in 2000 and 33,067,120 in the

current year (as shown in

), a growth of more than twice the 1994 Philippine official figure .22 Of these, 95.6% were from

15 on-grid power plants; 1 from a coal mine and 1 from a mill. At an estimated cost of

$20/tCO223, the external environment cost of the CARMA derived CO2 emission of Philippine

power plants in the current year equals $661,342,400.

22

The CARMA database contains detailed information on the carbon emissions of over 50,000 power plants and companies worldwide. The project is financed by the Confronting Climate Change Initiative at the Center for Global Development, an independent and non-partisan think tank in Washington DC. Emission data for US, Canada, EU and India are based on official reports. Otherwise, emission levels are estimated using a statistical model that was fitted for thousands of reporting plants of these countries. It welcomes comments in its website

23

As estimated in the World Bank Study „Winds of Change: East Asia‟s Sustainable Energy Future‟ May 2010


Final Report


Table 23. CO2 Emission of Selected Philippine Power Plants (in kTons)

Power Plant 2000 Current Year

Sual 6582 8181

Pagbilao 3564 4415

Calaca 3121 3851

Masinloc 3032 3766

Quezon Power 2558 3192

Santa Rita 1465 1843

Ilijan - 1435

Mindanao STEAG 0 1268

San Lorenzo 0 881

Naga 648 799

Toledo 604 742

Limay 463 573

Mabalacat Mill 0 494

Malaya 303 240

Semirara 158 194

Power Barge 117 112 139

Total (of 17) 23,345,077 33,067,120

Total (all PH Power Plants) 24,425,721 34,569,282

Source: www.carma.org

5.7 EFFICIENT USE OF ENERGY AND DEMAND SIDE MANAGEMENT

The DOE’s energy efficiency and conservation targets as well as their implementing strategies

keep shifting. From 82.56 MMBFOE (or an average of 8.256 annually) in the 2004-2013 PEP; it

was increased to 23.4 MMBFOE annually for the 2005-2014 planning period; scaled down to 7.5

MMBFOE in 2010 and upped to 9.1 MMBFOE by 2016 in PEP 2007-2016. The target was

changed to 10% energy savings on the total annual demand of all economic sectors in PEP 2009-

2018.

There is limited information available on performance against these targets. It was reported that

in 2006, the recorded energy savings was at 6.1 MMBFOE which was much lower than the 23.4

MMBFOE target at that time.24 Energy labeling and efficiency standards generated 2.03

MMBFOE or 33.3% of total savings achieved. Of this, over half , 1.13 MMBFOE came from the

24

PEP 2007-2016


Final Report


CFL project. Power losses as a percentage of total electricity consumption stayed at 12% in 2001

and 2009.25

Among the strategies identified by the DOE in PEP 2009-2018 are:

a) Power Patrol;

b) Partnership for Energy Responsive Companies;

c) Energy Standards & Labeling of Appliance/Equipment;

d) Government Enercon Program;

e) Energy Audit;

f) Energy Use Standard for Buildings;

g) Heat Rate Improvement of Power Plants; and

h) System-Loss Reduction.

In previous PEPs, the strategies also included the aggressive promotion of renewable energy.

The program appears to lack focus (some like the heat-rate improvement and energy building

standards have not been aggressively pursued) and a comprehensive policy framework that will

spell out incentives and penalties for non-compliance. The development of a policy framework

for Demand-Side Management that was assigned to the ERC in the EPIRA has not been started.

The ERC and the DOE had subsequently agreed that the latter will take charge of this but work

on the policy framework has yet to commence.26

5.8 AFFORDABLE, TRANSPARENT AND REASONABLE ELECTRICITY RATES

Whether the electricity rates after the EPIRA are affordable and reasonable is difficult to

evaluate inasmuch as the neither the regulator nor the DOE has determined the tariff level that

is affordable and reasonable tariff. At the same time, the complexity of the new rate setting

methodology for the transmission and distribution utilities and bilaterally negotiated purchase

power contracts tend to obscure the true cost of electricity from the public.

25

DOE Power Statistics 26

From interviews with ERC and DOE officials


Final Report


Data from the DOE shows that the effective electricity rates rose by 28.8% from 2003 to 2009.

As shown in Figure 15 and Figure 16, this national average was mirrored in Luzon where

electricity rates increased by 29% during the same period, albeit, with peaks that reached PhP

8.00/kWh that were not experienced in the Visayas and Mindanao grids.

Source: DOE EPIRA Reports 2007 Rates are estimate

Figure 15. Annual Average Effective Rates Rates (2000-2009)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

National 4.69 5.47 5.18 5.51 5.59 6.80 6.90 6.88 5.77 7.25

Luzon 4.82 5.62 5.31 5.71 5.90 7.29 8.05 8.03 6.40 7.73

0123456789

Pe

so/k

Wh


Final Report


Figure 16. NPC Annual Average Effective Rates (2003-2010)

The analysis of MERALCO’s 2010 billing statements in Table 24 indicates that generation and

transmission costs were behind the rate increases. Generation charges increased by an average

of 30% ; transmission by 48%. Distribution had no contribution because MERALCO’s 2003

unbundled charges continued to apply until 2010 when the ERC finally allowed the utility to

implement its approved rates under the Performance Based Methodology (PBR) . Tariffs are

certain to increase more with the implementation of MERALCO’s PBR rates where the

distribution charges alone are on average, 60.5% higher than their 2003 level.

The rise in MERALCO’s generation costs in 2008 to 2010 as shown in Figure 17 were caused by

the increasing prices of its 3 main suppliers, namely: IPPs, WESM, and NPC. WESM average

prices per kWh were at PhP 7.79 in 2010, PhP2.86 in 2009 and PhP4.87615 in 2008. Average

price of NPC were at its highest in 2010 at PhP 5.24/kWh and lowest in 2008 at PhP3.97/kWh.

Purchases from the IPPs had lower price fluctuations than those from WESM and NPC at an

average of PhP4.6/kWh during the 3 year period with its highest average at PhP/4.71/kWh in

2008.

0

1

2

3

4

5

6

2003 2004 2005 2006 2007 2008 2009 2010

Pes

o/k

Wh

Year


Final Report



Final Report


Table 24. MERALCO Comparative Charges1, 2003

2-2010

3 (Pesos)

Service Generation (per kWh)

4

Transmission (per kW except

residential)5

Distribution (per kWh)

6

Distribution (per kW)

6

Supply & Metering

(per customer/ month)

6

Residential 201-300 KWh

2003 3.4029 0.9605 1.6471 5

2010 4.2874 1.28 2.23 25.95

Change 25.99% 33.26% 35.39% 419.00%

General Service IS Small

2003 3.4029 258.31 0 141.87 973.07

2010 4.2874 376.5898 0.0259 247.87 1,309.79

Change 25.99% 45.79% 0.7472 34.60%

INDL IS Large Secondary

2003 3.4029 290.11 0 119.4 973.07

2010 4.2874 433.898 0.0259 247.87 14,382.97

Change 25.99% 49.56% 1.076 1378.10%

Comm NIS Large Below 13.2 Kv

2003 3.4029 294.57 0 112.94 973.07

2010 4.2874 469.2007 0.0259 188.56 14,382.97

Change 25.99% 59.28% 0.6696 1378.10%

Comm NIS Very Large 13.8/13.2 kV

2003 3.4029 300.1 0 123.27 1,096.34

2010 4.2874 469.2007 0.0259 188.56 31,509.08

Change 25.99% 56.35% 0.5297 2774.02%

Industrial IS Large 34.5 kV

2003 3.4029 311.4 0 124.62 1,096.34

2010 4.2874 503.5579 0.0259 188.56 31,509.08

Change 25.99% 61.71% 0.5131 2774.02%

Industrial IS Extra Large 115 kV

2003 3.4029 326.12 0 112.76 973.07

2010 4.2874 421.2338 0.0259 151.69 31,509.08

Change 25.99% 29.17% 0.3452 3138.11% 1 Excludes VAT, Energy Tax, Lifeline rate subsidy, special discount, power factor adjustment, power act reduction

2 Based on ERC Order of May 2003 on ERC Case No 2001-900 & 2001-646 „Re Application for Approval of Revision of

Rate Schedules and Appraisal of Properties With Prayer for Provisional Authority‟ and „In the Matter of the Application for Approval of the Revised Rate Schedule in Compliance with Section 36 of Republic Act No 9136 and ERC Order Dated October 30,2001 and for Approval of Appraisal of Properties, With Prayer for Provisional Authority: MERALCO, Applicant‟ 3 Based on MERALCO Summary Schedule of Rates Effective December 2010 Billing Month

4 MERALCO average generation cost in 2009 and ERC approved generation rates in 2003

5 MERALCO average transmission charges in 2010

62010 Distribution charges


Final Report


Figure 17. MERALCO Average Monthly Generation Cost (2008-2010)

The typical residential energy price and typical industrial regulated price in Chile are shown in

Figure 18 and Figure 19, respectively. For the residential customers, generation rate (energy +

power) is approximately PhP 5.59/kWh while distribution is approximately PhP 1.72/kWh. For

industrial customers, the generation rate comprises of an energy charge of approximately PhP

4.8/kWh; a power charge of approximately PhP43/kW at off-peak or at PhP 365.5/kW at peak

hours. The distribution charge is approximately PhP 64.5/kW. The transmission charge is

approximately 10% of the combined energy and power charge.

It will be noted that while the generation charge in the MERALCO franchise area is lower than in

Chile; the distribution charges for both residential and industrial customers are much higher.

For the typical residential customers , MERALCO’s distribution charge (exclusive of supply and

metering) are at PhP2.23/kWh vs. PhP 1.72/kWh for Chile. For industrial customers, MERALCO’s

lowest charge , i.e., for Extra Large Industrial Customers is 2.35x that of Chile.

Brazil‟s average tariffs are shown in Table 25. They are lower than MERALCO‟s charges for all

customer classes.

0

2

4

6

8

10

12

0 4 8 12 16 20 24 28 32 36

Ph

P/kW

h

Month

NPC WESM NPC & WESM IPPS AVERAGE


Final Report


Figure 18. Chile: Typical Residential Energy Price

Figure 19. Chile: Typical Industrial Regulated Price

Table 25. Brazil Average Electricity Prices, 2010

Type of

customer Average Tariff

(US$/MWh) (PhP/kWh)

Residential 153.49 6.68

Industrial 108.55 4.72

Commercial 147.60 6.42

Typical Residential

Energy Price

Typical Residential

Energy Price

Typical Industrial Regulated PriceTypical Industrial Regulated Price


Final Report


5.9 CONSUMER PROTECTION AND COMPETITION THROUGH A STRONG AND

INDEPENDENT REGULATOR

Consumer protection and the development of effective competition primarily depend on the

strength of the incentives for them in the policy framework and secondarily only on the strength

and independence of the regulator. The policy review that follows show that existing policies

such as vertical integration between generation and distribution and the improper sequencing

of reforms dulls competition and consequently, consumer protection. Since regulation only

implements policy, any shortcomings on the regulation side is normally corrected by policy

reform. However, there is strong evidence from this assessment and that of the policy

framework that the regulator, by its own omission and/or commission may have further

weakened consumer protection and competition. Examples of these are in the implementation

of the grid limits on generation capacity ; the implementation of the PBR for transmission and

distribution; and the fatally flawed Competition Rules and Complaints Procedures. At the same

time, the regulator is viewed as having taken its independence too far; to the point of making

coordination difficult with other agencies.


Final Report


6 ASSESSMENT OF INDUSTRY REGULATION

The industry’s regulatory system consists of the regulatory policy directions laid down in the

EPIRA and its Implementing Rules and Regulations (IRR) and the rules and regulations issued by

the regulator to carry them out. The assessment of these regulatory policies will focus on the

strength of their incentives to primarily, attract sufficient private investment in generation in the

Luzon grid and secondarily, contribute to economic efficiency.

A robust regulatory incentive structure aligns the regulatory objectives of economic efficiency

with the profit objective of the regulated firms. Economic efficiency refers to productive

efficiency, dynamic efficiency and allocative efficiency. Prices at marginal cost of production

(which includes a normal mark-up) are allocatively efficient. Those above and below are not. The

former diverts money from more productive activities while the latter leads to wasteful

consumption, insufficient private investment and government subsidies that crowd out other

essential public services such as education and health. Economic efficiency is induced by

effective competition which compels firms to eliminate slack, innovate, and adopt new

processes over time. However, the policy choice is not as straightforward in an industry such as

the electric power industry that is characterized by market power or, the ability to set price

above the marginal cost of production,. In this situation, economic efficiency is brought about

by a policy mix of market competition where it is possible and the regulation of sectors/activities

that are not competitive.

The rules that make up the regulatory incentive structure are intended to act as proxies to the

disciplines imposed by a fully competitive market that are largely absent from utility/network

industries. The principal objective of regulation is thus to ensure that utilities are provided

sufficient incentives to invest, increase their efficiency and reduce costs while maintaining or

improving the quality of service to their customers. A sound regulatory incentive structure

strikes the right balance between ensuring financially viable firms and low electricity rates. It

does not underwrite the financial viability of any particular entity if its viability is being

undermined by risky financial decisions or poor management performance. Neither does it

impose low rates that fail to recover the prudent and reasonable costs of the regulated entities.


Final Report


As in other network industries, the strength of the regulatory incentives in the electric power

industry rests on the structural policy adopted; liberalization; ownership; conduct regulation;

and the sequencing of policy reforms.

6.1 STRUCTURAL POLICY

6.1.1 VERTICAL SEPARATION OF TRANSMISSION FROM GENERATION AND

DISTRIBUTION

Transmission was vertically separated from generation and distribution. Section 45 of the

EPIRA27 prohibits generation companies, distribution utilities or their respective subsidiaries or

affiliates or stockholders or officials or other entities engaged in these businesses within the

fourth civil degree of consanguinity or affinity from holding any direct or indirect interest in

TRANSCO or its concessionaire and vice versa.

The need for close coordination between transmission and generation favors vertical integration.

However, this policy would restrict competition in generation. To promote competition between

embedded and independent generators, the transmission company could be required to

undertake competitive tendering for additional generating capacity and provide third-party

access to independent generators. However these alternatives will require a strong regulator;

one with not only the adequate powers but the capacity to monitor and ensure that

transactions are arms-length and that the transmission company does not discriminate against

independent generators. Vertical separation is the most radical policy alternative but offers the

most prospect for the horizontal separation and liberalization of generation. Given the EPIRA’s

policy mandate to open generation to competition and to sell-off the generating assets of NPC,

vertical separation of transmission from generation and distribution was the logical policy choice.

6.1.2 VERTICAL INTEGRATION OF GENERATION AND DISTRIBUTION

27

Section 45 is on Cross Ownership, Market Power Abuse and Anti-Competitive Behavior


Final Report


There is no categorical policy statement favoring vertical integration between distribution and

generation in the EPIRA. Instead, it is implied in paragraph 3 of Section 45 c) that prohibits ERC

from imposing restrictions on ownership and control outside those required to enforce the

provisions on competition, market abuse and anti-competitive behavior of this Section. Thus,

while a finding of anti-competitive conduct and/or violation of competition rules can force de-

integration; vertical separation is not an ex-ante policy . The relevant sentence in paragraph 3

reads:

“Except as otherwise provided for in this Section, any restriction on ownership

and/or control between or within sectors of the electricity industry may be

imposed by ERC only insofar as the enforcement of the provisions of this Section

is concerned”.

To avoid abuse of market power, Section 45 limits to 50% of its total demand the amount of

energy that a distributor can source from bilateral supply contracts with an associated firm

except for those contracts concluded before the EPIRA. A distributor is also obliged under

Section 2328 to “supply electricity in the least cost manner to its captive market” which is akin to

the economic sourcing obligation imposed in other regulatory jurisdictions abroad.

Except for the reduction of transaction cost, there is hardly any economic justification for

vertical integration. There is very little economies of scope between distribution and generation.

In contrast, the downside risk of anti-competitive conduct by the integrated utility and

disincentive to new entrants are very high. Vertical integration could lead to uneconomic

sourcing where the distributor favors its own generation over cheaper competitors, exclusionary

conduct and discriminatory access terms to the network. To limit the harm to competition, the

vertically integrated utility is: a) subjected to regular audit; b) required to undertake competitive

tendering for its energy requirement and to strictly comply with its economic sourcing

obligation; and c) required to provide non-discriminatory access to the network. These

safeguards usually require a complicated regulatory oversight to succeed including a skillful and

vigilant regulator. Despite these safeguards, regulating a vertically integrated utility is a tough

28

Section 23 is on Functions on Distribution Utilities


Final Report


challenge to even the most skillful regulator because the former has both the incentive and the

ability to circumvent nondiscrimination rules which are against their self-interest, not the least

due to information asymmetry. Thus, vertical separation is the better policy choice in regulatory

jurisdictions with limited administrative capacity.

The challenge of regulating a vertically integrated utility is especially difficult in the Luzon grid

where nearly 70% of electricity demand is supplied by a single distributor, MERALCO. With its

dominance of the grid’s distribution network and electricity supply, the utility can single

handedly influence the entry and profitability of competing generation investments as well as

the end-user price of electricity. MERALCO ceased buying from NPC and defaulted on its

contract obligation when its affiliate generators came on stream in 2003. A compromise

settlement amounting to PhP13 Billion, down from the original disputed amount of PhP30

Billion, was eventually reached by the two parties with the approval of the regulator. But

instead of paying the penalty itself, the regulator allowed MERALCO to pass on and collect the

settlement charge from its customers. 29 A study conducted in 2008 by the University of the

Philippines using an optimization model found that MERALCO had violated its economic

sourcing obligation by sourcing higher priced energy from its affiliates which caused end-user

prices to be PhP 0.62/kWh higher than would have been the case had the utility bought from

non-affiliated generators instead.30

Ex-post de-integration is difficult to achieve because it threatens to harm private stockholders

who can be expected to legally challenge a policy re-direction. Again, this will be particularly

difficult in Luzon because of MERALCO’s affiliation with generating plants. While the Lopez

group has largely divested from MERALCO its place has been taken over by San Miguel Energy

Corporation. SMEC owns 27% of MERALCO and now accounts for nearly 30% of Luzon’s

generating capacity.

29

On appeal from the Office of the Solicitor General, the Court Appeals recently ruled that NPC does not have the authority to enter into a settlement 30

Del Mundo Rowaldo, et al „Analysis of Power Supply Purchases of MERALCO for the Year 2007 and 1

st Quarter of 2008‟


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A policy of vertical separation need not be an all or nothing agenda. Since some distribution

utilities had integrated to generation under the current policy framework; a standstill

agreement may be enforced. That is, distributors need not divest from generating plants that

supply their load requirement provided that: a) no new additional investments will be made; b)

all bilateral power purchase contracts will undergo competitive public tenders; c) economic

sourcing obligation will be strictly complied with; and, d) violation of any one of these conditions

and/or the competition rules will result in forced divestment.

6.1.3 HORIZONTAL SEPARATION OF GENERATION

EPIRA’s Mandate

A policy of horizontal separation of generation was mandated in the EPIRA in order to promote

competition and prevent the abuse of market power. An alternative policy option, i.e., vesting

contracts is not provided in the law.31 Vesting contracts has the advantage of promoting scale

economies while curbing abuse of market power by requiring dominant generators to dedicate

a prescribed portion of their capacity to designated end-users at regulated prices pending the

achievement of effective competition in generation. However, the regulator’s inability to

correctly implement horizontal separation does not bode well for its ability to grapple with the

complexities of vesting contracts. Besides, technological developments in generation have

brought down the minimum efficient scale in generation; e,g., it is exhausted at 300-400 MW in

CCGT plants.

The policy directive for Horizontal separation is provided in Section 45 of the EPIRA. This policy

prohibits the ownership, operation or control by any company or related group of more than

thirty percent of the installed generating capacity of the grid and/or twenty-five percent of the

national installed generating capacity. Rule 11 Section 4(a) of its IRR added IPP Administrators

among those covered by the prohibition and clarified that the prohibition applies either “singly

31

Vesting contracts are bilateral electricity contracts that are imposed by the regulator on large incumbent utilities in order to curb their market power and promote efficiency and competition in the market. With these contracts, the generators are required to sell a specified amount of electricity at a specified price to distribution companies for the benefit of primarily, the captive customers and at times, also to serve a part of the contestable customer demand.


Final Report


or in combination.” Such restrictions do not apply to PSALM and NPC while their assets are

being privatized.

Related group is defined in Section 45a) as including “a person’s business interests, including its

subsidiaries, affiliates, directors or officers or any of their relatives by consanguinity or affinity,

legitimate or common law, within the fourth civil degree.”32

Rule 11 Section 4 of the IRR prescribes a methodology for crediting the capacity of a generating

facility with different owners or where it is owned, operated or controlled by different persons,

viz:

“(b) The capacity of such facility shall be credited to the entity controlling the

terms and conditions of the prices or quantities of the output of such capacity

sold in the market in cases where different entities own the same Generation

Facility.

In cases where different Persons own, operate or control the same generation

facility, the capacity of such facility shall be credited to the Person controlling the

capacity of the Generation Facility” (underscoring supplied)

Control of the output, i.e., the installed generating capacity is the key determinant of market

power. Either by oversight or by design, the Rules extends the prohibition to a Person/group

that owns, operates or controls the facility but does not control the prices and/or the level of its

output that is sold in the market. This is the situation of the owners and operators of IPP plants

whose capacities are, with few exceptions fully contracted to the NPC. Under the current rules,

they will be credited with capacities that they do not control and will unnecessarily be

prevented from investing in additional generating capacities once they have reached the limit.

This logic appears to have guided the ERC in its implementation of the policy , albeit, one that

violates the law.

Implementation by the Regulator

In 2005, the ERC through Resolution No. 26 Series of 2005 came out with the guidelines for

determining and crediting the installed generating capacity in a grid. The guidelines amend the

32

EPIRA, Section 45a)


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law and explain why the ERC has not found any company or group to have violated the limits ;

why the Lopez’ group acquisition of Unified Leyte in 200733 and its subsequent purchase of

Tongonan I and the Palinpinon plants in 2009 were allowed to proceed notwithstanding that

these caused the group to breach the 30% grid limit ; and the San Miguel group’s plans to

invest in more power plants in the Luzon grid.

Section 4 of the ERC guidelines reads:

“Section 4. Crediting of Generating Capacity

In crediting generating capacity of a generation facility in favor of one or more persons or entities, which own, operate, or control such generation facility, the following rules shall be observed:

a. If different entities own the same generation facility, the capacity of such facility shall be credited to the entity controlling the terms and conditions of the prices or quantities of the output sold in the market. b. If an entity owns the generation facility and some other entity or entities operate or exercise control over such facility, pursuant to a maintenance or operating contract, lease, assignment, joint venture agreement , or any other similar arrangement, the capacity of such facility shall be credited to the entity or entities controlling such capacity, to the extent subject of its or their control, and not to the entity owning the generation facility. c. Consistent with the foregoing, in the case of NPC and its independent Power Producers (IPPs), it is the control and not the ownership of the power plants which determines who should be credited with the total capacity under contract as it is NPC that actually controls the quantity (dispatch level) generated from the subject power plants and the price of electricity offered to the market. Thus, NPC will be credited the contracted capacity while the remaining capacity not under contract will be credited to the owner of the plant or the entity exercising control over such remaining capacity, in accordance with the preceding rules.”

Section 4 c) above is inconsistent with the law and its IRR. The language of the latter is such that

the cap separately and equally applies to ownership as well as to the operation or control of the

installed generating capacity. Moreover, Section 4(c) of Rule 4 of the IRR only applies to a

generation facility with different owners or one which is owned, operated or controlled by

separate entities.

33

With the purchase, the Lopez group breached the grid limit


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Based on ERC’s data as of October 4, 2010 the Lopez group at that time owned, operated and

controlled 54.4% of the installed generating capacity in the Visayas grid. 34 Nearly 69% of this or

668 MW represents the installed generating capacity of Unified Leyte that the group acquired

when the government decided to sell its remaining majority stake in PNOC-EDC. While the

capacities of the plants are covered by a PPA contract and controlled by NPC; ownership, control

and operation of the facility is with the Lopez group. The capacities can only be credited to NPC

had the facilities been owned by different entities or had they been owned, operated or

controlled by different persons. Since neither of these conditions applies in this case; the Lopez

group is caught by the general prohibition against ownership, operation or control of more than

30% of the installed generating capacity limit in a grid and more than 25% of the national grid

limit. Had control of the installed generating capacity been the criterion regardless of who owns

and operates the facility, the share of the Lopez group of the grid’s installed generating capacity

in October 2010 would have been reduced to 20.7% in October 2010 and 17% in March 2011.

The remaining capacity owned, operated and controlled by the Lopes group in the Visayas are

those of the Tongonan I, Palinpinon I and II geothermal plants which were previously owned by

NPC and were bought by the group from PSALM in 2009. Unlike Unified Leyte, their capacities

are not under covered by a PPA with NPC. Because of this, ERC correctly credited their

capacities to the Lopez group.

With respect to the IPPs that are now under administration, it is clear from Section 31 of the law

that the management and control of the energy output of the plants will be transferred to the

Administrator. This is confirmed in the IPPA Agreements. For instance, Annex 5 to Section B –

Delivery of Power and Energy of the IPPA Agreement for the Sual Coal Fired Power Plant

between PSALM and San Miguel states that:

“2. The Administrator shall be entitled to the management and control of the Capacity of the Units and shall pay the Monthly Payments in respect of, inter alia, such rights”.

34

ERC „Resolution No 20, Series of 2010: A Resolution Setting the Installed Generating Capacity Per Grid, National Grid and the Market Share Limitations Per Grid and the National Grid for 2010‟, Oct 4, 2010


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Like Unified Leyte, these facilities are exclusively owned, operated and controlled by the IPPs.

However, since their capacities are now controlled by the administrator by virtue of the IPP

Agreement the administrators are caught by the general prohibition against the control of the

installed generating capacity in excess of 30% of the grid total and/or 25% of the national grid.

But as in the case of Unified Leyte, the ERC wrongly credited these capacities to the NPC in line

with Section 4c) of its Resolution No. 26 Series of 2005.

Resolution No. 26 further complicates the determination of a breach by defining installed

generating capacity in a manner that could not have been remotely envisaged in the law.

Section 2 of Resolution 26 acknowledges that the installed generating capacity is its maximum

output or nameplate rating. However, in determining the installed capacity of each plant the

guidelines adjusts the same by netting out: a) permanent reductions; b) temporary reductions

due to plant shut down in the preceding 12 months; and, c) temporary reductions due to

transmission constraint that are expected in the next 12 months from the determination. As a

consequence, the installed generating capacity of each company/related group as well as the

total for each grid as determined by the ERC fluctuates yearly as revealed in a review of its

annual determinations from 2005 to 2010.

These adjustments are not provided in the law where the limitation strictly applies to installed

generating capacity. While the adjustment for permanent reduction or derating may be

reasonable; adjustment for temporary reduction is much more problematic and should never be

allowed. Aside from complicating the determination of a breach, i.e., a company may be in

breach one year and not in the following year; it can be used to circumvent the grid limits and

nullify its objective to prevent the abuse of market power by those who may be inclined to do

so.

ERC’s unilateral adjustments to the installed generating capacity makes it difficult to ascertain

whether or not a company/related group whose share is in the border of 30% is still within the

limit. A case in point is the San Miguel group. Table 26 shows disparate data from ERC, PSALM,

and DOE on installed generating capacities now owned, operated and/controlled by the group.

The group is well within the limit based on ERC’s data but is close to breaching it based on

DOE’s. Note that DOE’s data are based on nameplate rating.


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Table 26. Installed Generating Capacities of the San Miguel Group in the Luzon Grid

Plant Installed Generating Capacity (MW)

Status ERC 2010 PSALM DOE

Limay CGCT 603.5 620 620 Owned, operated and controlled

Sual 218 1,000 1,294 IPPA; capacity controlled

Ilijan 36.3 1,200 1,271 IPPA; capacity controlled

San Roque 66 345 345 IPPA; capacity controlled

Total San Miguel 923.8 3,165 3,530

Total Luzon Grid 10,839 NA 11,863

San Miguel share (%) 8.5 NA 29.75 Source: ERC Resolution No. 20 Series of 2005 ; PSALM’s declared capacities of generating plants transferred to administrators; DOE List of Generating Plants in 2009.

The installed capacities in Luzon that are controlled by the Lopez and Aboitiz groups are shown

in

Table 27 Unlike in the San Miguel group’s , there is only a slight difference between the

capacities recorded by the ERC and the DOE. Figure 20 shows that San Miguel has the biggest

capacity from the point of view of control if the IPPA contracted capacity is included in its

capacity credit.

Table 27. Installed Generating Capacities of Lopez and Aboitiz Groups in Luzon Grid

Group/Plant

2010 Installed Generating Capacity (MW) Status

ERC DOE

Lopez Group

Pantabangan-Masiway 112 112 Owned, operated and controlled

Bac-Man 36 150 Owned, operated and controlled

Sta Rita 1,036 1050 Owned, operated and controlled

San Lorenzo 526 500 Owned, operated and controlled

Total Lopez Group 1,710 1,812

% to Luzon 15.77 15.27

Aboitiz Group

Magat HEPP 360 360 Owned,operated and controlled

Tiwi GPP 169.1 275.69 Owned, operated and controlled

Mak-ban GPP 281.25 458.43 Owned, operated and controlled

Ambuklao HEPP 0 75 Owned, operated and controlled

Binga HEPP 100 100 Owned, operated and controlled


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Pagbilao 700 728 IPPA; capacity controlled

Total Aboitiz Group 1,610.35 1,997.12

% Luzon 14.85 16.83

Total Luzon 10,839 11,863

Figure 20. Control of 2010 Installed Generating Capacity, Luzon

6.2 OWNERSHIP

The main policy mandates on ownership are on the privatization of NPC’s assets and IPP

contracts and democratization. While the law did not directly address the ownership of Electric

Cooperatives; that issue will be examined in this study because of its relevance to the question

of incentives and generation investments in the Luzon grid.

6.2.1 PRIVATIZATION OF NPC ASSETS AND IPP CONTRACTS

EPIRA privatized the transmission and generation assets of NPC including its IPP contracts. NPC

is allowed to generate and sell electricity from the unsold generating assets/IPP capacity only

and is prohibited from concluding power purchase contracts with other generators or suppliers.

San Miguel

30%Lopez15%

Aboitiz17%

NPC16%

Others22%

Control of Installed Capacity, Luzon


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It must conclude transition supply contracts with distribution companies which shall be

assignable to its successor generating companies.35

There was no need for a similar policy mandate for distribution utilities which were already

privately owned, with the exception of 2 LGU owned utilities that were subsequently sold to

private investors.

6.2.2 DEMOCRATIZATION

The law limits to at most 25% of the voting shares of stock of a distribution utility that may be

held by Persons, including directors, officers and stockholders and related interests unless the

utility or its controlling shareholders are already listed in the Philippine Stock Exchange (PSE) . It

requires the controlling shareholders of small distribution utilities to list in the PSE within 5

years from the time they acquire ownership or control and mandates generation companies and

distribution utilities to sell to the public at least 15% of their common shares.

Section 28 explains that the 25% limit and the requirement to list are “in compliance with the

constitutional mandate for dispersal of ownership and de-monopolization of public utilities...”.

It does not provide any economic efficiency justification for this intrusion into corporate

structure and control of private companies. The biggest motivator or incentive in private

companies is control. Unless there is compelling evidence that such limitation yields significant

economic efficiencies; a better policy course would be to create vibrant financial markets and to

remove legal and economic barriers to entry into the electric power industry.

Democratization is not a Constitutional mandate. The State is only directed to “encourage

equity participation in public utilities by the general public”.(underscoring supplied)36. As for

monopolies, the Constitution mandates the regulation or prohibition of monopolies when

required by public interest. Generation is no longer a monopoly while transmission and

distribution are regulated natural monopolies. Monopolization, which describes an

35

Sec 67 36

1987 Philippine Constitution, Art XII(11)


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action/conduct of a monopolist to exclude potential competitors is covered by the prohibitions

in Section 45 of the law.

6.2.3 OWNERSHIP OF ELECTRIC COOPERATIVES

There are 120 ECs nationwide. Of these, 55 operate in Luzon including 12 off-grid. Their

aggregate electricity sales in 2009 was 5,430,395 MWh or 14.3% of total electricity sales in

Luzon that year with a peak demand of 1,272 MW which was 18% of the grid wide peak.

Because of their predominantly residential and small commercial consumer base, ECs are

expected to continue as retail suppliers to most end-users in these markets even with retail

competition. In Luzon, only 3 ECs (INEC, ISELCO, SORECO) have embedded generating plants

with combined capacities of 8 MW.

ECs are non-profit and non-stock institutions that are exclusively owned by all their consumers.

Their operating, maintenance, capital expenses (equal to 5% of operating revenue in tariff

allowance) and taxes are fully funded by the consumers through the tariffs. Because consumers

provide funding for capital investment and debt service, the tariff does not provide for

depreciation and return on investment.

PSALM’s statements of account as of December 31, 2010 showed 16 Luzon ECs with power bill

payables of more than 60 days; accrued VAT remittances and accumulated interests including

restructured accounts . Except for Batangas II Electric Cooperative (BATELEC-II), all the ECs

experienced negative operating margins in 2010 as reported in NEA’s annual financial statistics.

The average collection efficiency of the Luzon ECs is around 94%. Despite this, 22 on-grid ECs

incurred net losses in 2009 and 17 in 2010. They accounted for 46% and 42% of total energy

purchases of the Luzon ECs in 2009 and 2010, respectively. The on-grid ECs that incurred losses

include 11 of the biggest in terms of yearly electricity sales, i.e.; over 100,000 MWh . Three-

Pampanga II and III and Albay Electric Cooperatives are among those with huge arrears with


Final Report


NPC/PSALM and are being closely monitored by NEA. Due to their size, the thirteen are able to

collect annual reinvestment allowance ranging from PhP 30 Million to PhP 79 Million. 37

which rules out lack of investible funds as the cause of their financial difficulties.

Among the policy measures taken by the government to strengthen the ECs since the enactment

of the EPIRA were:

a) Loan Condonation. Section 60 of the EPIRA directed PSALM to assume all

outstanding financial obligations that were incurred by the ECs for rural

electrification. But in exchange, the ERC was directed to reduce their tariffs by an

amount corresponding to the loans condoned over a period of five years. The

reduction ranged from PhP0.25 – PhP0.40/kWh which further strained the ECs’

finances.

b) Investment Management Contracts Scheme (IMC). The program was conceived for

ECs whose operating and financial performance could be turned-around with

management expertise from the private sector but with low investment

requirement. During the long gap between project conceptualization and

implementation however, the financial condition of the eight pilot ECs had

deteriorated to the point of requiring massive capital infusion. Few private investors

were willing to join a scheme that will require them to invest their own capital

without the management control that was retained by the EC Board of Directors. In

the end, two contracts were signed. These collapsed prematurely because of inter-

alia; the contracts strayed from the program’s guiding principles; weak project

oversight by the DOE and resistance from the EC stakeholders. 38

c) New Rate-Setting Methodology. The ERC introduced a new rate setting

methodology in 2009 for on-grid ECs. This would have increased the tariffs of 56 by

as much as 64% and reduced those of rest. The stiff opposition to tariff reduction

moved the ERC to maintain the tariffs of those affected at their old levels. The new

37

NEA „Status of Financial and Technical Operation as of December 31, 2009‟ 38

Based on the program evaluation of a member of this study team who was contracted by the DOE to conduct a third-party review of the IMC.


Final Report


methodology allows the ECs to collect additional contribution from the members to

fund capital deficiency through existing legal procedures.

d) Option to Convert into Stock Corporations under the SEC or Stock Cooperatives

under the CDA. Only 10 ECs converted to stock cooperatives; 9 of them in Luzon.

None has converted into stock corporations. The poor uptake is partly due to

resistance from the EC management and employees (and even from some NEA

officials/employees); reluctance of some ECs to lose NEA’s authority to discipline

and remove undesirable Board members that would result with conversion to stock

cooperatives and the lack of technical and financial capability of the Cooperative

Development Authority (CDA) to support their operations. ECs that joined the CDA

were mainly motivated by the continuing tax exemption available from membership

that had expired for those with NEA.

These measures do not directly address the possible link between the ECs’ ownership structure

and their operating efficiency. It is generally the case that privately owned firms are more

productively efficient than State Owned Enterprises (SOEs) because of their exclusive focus on

profitability. The Board of Directors appoints and monitors the performance of the managers to

induce them to behave in the owners’ interest. In companies with dispersed ownership such as

public companies, the threat of capital market disciplines such as takeover, regulatory

monitoring of their corporate practices makes up for weaker shareholder control and discourage

costly managerial discretion.

ECs are privately owned by all their consumers. However, they lack the tight control over

management and single-minded focus on profitability that characterizes their PDU counterparts.

Instead, their current ownership and management structures have strong built in disincentives

for productive efficiency, namely: (1) wide ownership dispersal (many consumers do not even

know that they own the utility) without the strict discipline imposed by capital markets ; (2) the

absence of a profit motive; and (3) politicization of the Board of Directors that owe their loyalty

to their political sponsors rather than to the owners that they are supposed to represent.


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Two benchmarking studies on the ECs technical efficiency showed efficiency scores that were far

behind the efficient cost frontier. Both studies excluded power cost from the cost drivers and

included the size of the franchise area. Their findings suggest large potential for cost savings by

reducing productive inefficiencies. The first study conducted in 2004 covered 105 ECs.39 With

data on the ECs’ operations from 1990-2002, the study employed Stochastic Frontier Analysis

(SFA) and Data Envelopment Analysis (DEA) to calculate their relative efficiencies. It found that

on average, the ECs were 34% away from the frontier under the SFA and 42% under the DEA.

The second study was conducted in 2006 and employed DEA only with data sets from 2001-

2005.40 It excluded all 21 off-grid ECs and 31 on-grid ECs with incomplete data sets.41 Over half

of the on-grid ECs excluded were in the bottom-half of the efficiency ranking in the first study.

The study recorded a lower average inefficiency score of 19%.

Mitigating the damage on the ECs productive efficiency may require the consolidation of their

ownership to a small group of equity investors – preferably consumers of the EC, whose profit

motive coupled with effective regulatory restraint could induce productive efficiency. The

process will necessarily involve valuation of the business as a going concern; buying out the

existing owners-consumers and registration either as Stock Corporations or Stock Cooperatives.

6.3 LIBERALIZATION AND DEREGULATION

6.3.1 GENERATION AND ELECTRICITY MARKETS

Generation was immediately opened to competition, de-classified as a utility and exempted

from the franchise requirement by the EPIRA. The wholesale and retail electricity markets were

liberalized. A wholesale electricity spot market (WESM) was created: WESM Luzon and WESM

39

Lavado, Rouselle „Benchmarking the Efficiency of Philippine Electric Cooperatives Using Stochastic Frontier Analysis and Data Envelopment Analysis‟, 2004. The study states that 119 ECs were covered but only 105 , 6 of them off-grid are in the data sets. 40

NEA/UPNEC/EC-ASEAN Energy Facility „Performance-Based Regulation for Electric Cooperatives in the Philippines Technical Report 2: Efficiency Benchmarking of Philippine Electric Cooperatives for Performance –Based Regulation‟, 2006 41

Off-grid ECs do not have substations or have small substations only. They were removed to avoid distorting the efficiency results.


Final Report


Visayas went live in June 2006 and in December 2010 respectively. Retail competition will

commence as soon as prior-conditions are achieved, namely: (a) establishment WESM; (b)

approval of unbundled transmission and distribution wheeling charges; (c) initial

implementation of the cross subsidy removal scheme; (d) privatization of at least 70% of the

total capacity of generating assets of NPC in Luzon and Visayas; and, (e) transfer of the

management and control of at least 70% of the total energy output of power plants under

contract with NPC to the IPP Administrators. All these conditions have been met. Generation

rates and retail supply are to be deregulated when retail competition sets in. These radical

policy reforms were intended to attract private investments in generation, induce competition

and create an efficient domestic electricity market.

The immediate removal of the legal barriers to entry and the operation WESM in 2006 failed to

attract the expected high level of new investments in generation. From 2002 to 2009 only 33

MW from new investments that were committed after the EPIRA was passed were added to the

generating capacity in Luzon; 66.4 MW in the Visayas and none in Mindanao. An additional 600

MW is expected to come on-stream in Luzon by 2013; 671 MW in the Visayas and 100 MW in

Mindanao.

To understand the underinvestment requires an appreciation of the allocation of the risks

associated with large, sunk and long-term investments in power plants in a single buyer

regulated environment and in a liberalized, deregulated environment. In the former, the

customer bears all the risks as in the case of the IPP contracts signed by NPC. In the other, the

risks are internalized and borne by the investor. In order to commit, the investor must have a

sufficient degree of certainty on the recoverability and profitability of such investments. In the

first place, project finance has to be raised and the financiers have to be assured of payment

before extending financing. The collapse of the US wholesale electricity markets in 2001

practically dried up financing for merchant plants without long-term contracts.

Given these altered environment decisions to invest are more than ever based on long–term

fundamentals, market design, market structure and policy support that mitigate such risks; not

on short-term price spikes such as those that occasionally obtain in the spot market. Since


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radical policy reforms especially one attended by a change-over from subsidized government

utilities to privately owned profit maximizing utilities inevitably result in a period of uncertainty

and price increases; credible government commitment to the reforms or at least refusal to slide

back to populist policies and regulatory capacity to deal with the complexities of new market

designs and processes and the problems that these create are critical to the decision to invest.

Unfortunately, these were mostly lacking in the wake of the EPIRA and continue to be so.

Industry participants, consumers and observers alike are dismissive of the regulator’s technical

and administrative capacity and the DOE has mostly conceded to the ERC even in those areas

where it is supposed to lead.42 Concerns over political intervention in regulatory decisions were

raised when the then President ordered the NPC/ERC to cap the PPC of IPP contracts at PhP0.40

less than a year into the EPIRA following consumer protests over increased electricity prices.43

The credibility of the reform process was then undermined by missed timelines for major policy

initiatives laid down in the law, which were unrealistic to start with.

The Spot Market and Generation Adequacy

Under idealized conditions, competitive wholesale electricity markets send out efficient price

signals that attract a mix and amount of new generation investments consistent with reliability

criteria. Experience around the world had shown otherwise. The principal cause appears to be

the “missing money” or net revenue gap, i.e.; the net revenues earned in energy markets over

time fail to cover the capital cost of generating electricity.44 This gap is in turn attributed to, in

order of importance: (a) system operation protocols and behavior of the system operator to

maintain network reliability and prevent network collapse that depress wholesale prices in

times of scarcity or hides the marginal social cost of voltage reduction; (b) inelastic prices caused

by the consumers’ inability to react to changes in the supply and demand balance; and (c) price

caps, must–offer obligations and other regulatory interventions in the market to prevent abuse

42

Based on interviews conducted by a member of the study team for an ADB study on the Philippines‟ regulatory policies in the energy sector 43

NPC‟s unbundled generation rate has 3 components: fuel, PPC and basic charge. IPP contracts were split into PPC – that was capped by the President and amortization of capacity fees which falls under the basic charge. 44

For a discussion of the „missing money‟ problem, refer to Cramton Peter and Steven Stoft „The Convergence of Market Designs for Adequate Generating Capacity, White Paper for California Electricity Oversight Board, March 2006


Final Report


of market power.45 Some policy proposals had been advanced by noted international regulatory

experts that in combination, will close the revenue gap and incent new investments.46 These

include: (a) the adjustment of reliability rules and protocols that were a legacy of vertically

integrated utilities to make them consistent with consumer valuation; (b) improved market

design such as raising the price cap; (c) forward energy hedging contracts; and (d) forward

capacity markets. These proposals are difficult to implement and get right. They will not

happen overnight especially not in the Philippines where a liquid and complete capital markets

have yet to come out despite years of effort and with its fragile regulatory institutions.

Physical Contracts and Generation Adequacy

The current supply shortage compels the adoption of solutions that will induce investment in

new generating capacities at the soonest possible time even at the expense of postponing some

of the efficiency gains from liberalizing the electricity markets. Effective competition and

economic efficiency can hardly be expected to materialize with supply shortages even in

liberalized electricity markets, anyway.

Under current conditions, forward power purchase contracts for physical delivery has the most

potential to incent new investments. It minimizes market risk that then allows investors to raise

project finance. ERC Resolution No 21 Series of 2005 [Box No. 2] requires DUs to sign bilateral

supply contracts but fails to specify the quantity to be contracted, the duration of the contract,

when the contract must be entered into and the penalty for non-compliance. Compliance had

been spotty due to these and because the DUs are increasingly averse to being locked in long-

term contracts that are often one-sided in favor of the supplier. In addition, long-delays in the

approval and ex-post arbitrary changes to the contract terms by the regulator alter their

carefully negotiated financial structures and deter prospective investors.

Box No. 2 - Excerpt, ERC Resolution No. 21 Series of 2005

45

Joskow Paul „Competitive Electricity Markets and Investments in New Generating Capacity The New Energy Paradigm‟ Oxford University Press, 2007 46

Ibid


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WHEREAS, to ensure that there will be sufficient supply of electricity in preparation for the

implementation of the wholesale electricity spot market, a bilateral contract should be entered into by

and between the distribution utilities and power suppliers to obtain generation and/or ancillary

services of a given type, quantity, duration, timing and reliability over a contractual term

NOW WHEREFORE, BE IT RESOLVED…. All DUs are hereby directed to enter into future bilateral power

supply contract with power producers to be subjected to a review by the Commission

To incent investment, the requirement for bilateral contracts must:

a) be mandatory;

b) prescribe the duration of the contracts such as say for the next 10 to 15 years;

c) mandate immediate compliance;

d) require 100% coverage of forecast load requirement; and

e) impose stiff penalties for non-compliance.

To capture some of the efficiencies of competition, purchase contracts should be publicly

auctioned instead of negotiated bilaterally between the DU and the supplier. The regulator can

draw-up, with inputs from stakeholders , and prescribe the use of a standard contract that will

protect the interest of both the supplier and buyer in the transaction. The contract shall also

provide for the carve out of a portion of the capacity contracted, e.g., in an amount equal to the

size of the DUs contestable market, from the coverage of the contract without giving rise to

stranded costs when retail competition is declared. The general framework of the auction shall

be akin to the Chilean framework as follows:47

1 Distributors shall be 100% contracted at all times.

2 Contracts shall be for 10-15 years;

47

A detailed description of the Chilean auction framework is provided in Part II of this Study and in Moreno, R et. Al, Auction Approaches of Long-Term Contracts to Ensure Generation Investment in Electricity Markets: Lessons from the Brazilian and Chilean Experiences, Energy Policy (2010), doi:10.1016/j.enpol.2010.05.026


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3 Each distributor shall draw up its own criteria , and auction its own

requirements subject to the approval by the regulator ;

4 Distributors can aggregate and simultaneously auction their requirements;

The advantages of public auction over bilaterally negotiated contracts are:

a) It captures some of the efficiencies of liberalized markets through the process of

competing for the market;

b) Transparency and efficient price discovery;

c) Minimizes regulatory opportunism because price caps per technology are set ex-

ante;

d) Ensures that small buyers can contract efficiently because under the system, the

aggregated load is bidded out by technology instead of by prospective buyer; and

e) Removes self-dealing by integrated utilities by requiring them to auction off all their

requirements .

Retail Competition and Generation Adequacy

Retail competition as directed by the EPIRA shall commence upon the implementation of open

access. Electricity end-users with a monthly average peak demand of at least 1 MW for the

preceding 12 months shall be immediately allowed to choose their supplier; those with 750 kW,

two years after. The threshold shall be subsequently lowered until it reaches the household

demand level.

The 1 MW and 750 kW thresholds appear to be arbitrary. More than this, postponing retail

competition is inevitable under current conditions. First, there cannot be meaningful customer

choice with supply shortage although large industrial customers may have some advantage.

Second, the conditions necessary to facilitate actual entry by competing suppliers and customer

switching , moderate the advantage of incumbents, and for the efficient working of the retail

market are still absent. These conditions were precisely recognized by the ERC as “vital

requirements” prior to declaring retail competition and open access in ERC Resolution No. 3 ,


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Series of 2007 titled “ A Resolution Indicating the Timelines for Full Retail Competition and Open

Access in Luzon”. Paragraph 1 of the Resolution describes these vital requirements as:

“the adequacy and establishment of all necessary in infrastructures including

but not limited to: transmission networks, generation supply and the customer

switching systems, and the promulgation by the ERC of all pertinent rules and

regulations governing Retail Competition and Open Access”.

The conditions necessary to encourage customer switching, facilitate entry of competing

suppliers and the smooth working of the retail market should include:

a) Publication by the ERC of the full list of contestable customers at least 3 years before

retail competition sets in to give new entrants time to market and build new

capacities, where so desired . The lists submitted by the DUs are reportedly covered

by a non-disclosure agreement. The customers came about as a result of the DUs’

monopoly positions; not through their own marketing efforts, hence, problems of

incentive and confidentiality do not arise from the publication of the list. Non-

disclosure impedes entry, maintains the incumbents’ advantage and runs counter to

the law’s objective to create retail competition.;

b) A requirement for DUs to provide their contestable customers with complete energy

information (e.g. hourly meter reading data). These data are not currently provided

by the DUs who inform their customers of their aggregate monthly energy data and

peak demand for the month;

c) Completion by the ERC of the rules and guidelines for the smooth working of the

retail market, such as on:

i. the settlement of imbalances, line rentals, and net settlement surplus

between DUs and Retail Electricity Suppliers (RES);


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ii. the performance of duties and responsibilities of the Philippine

Electricity Market Corporation as the Central Registry Body for Retail

Electricity Supply;

iii. the settlement of disputes for Contestable Customers;

iv. the standards for the metering facilities for Contestable Customers, the

responsibilities and standards of performance of the DU as the meter

service provider therefor, and the rates for such services;

v. amendment of ERC Res. No. 20, series of 2005 to provide for the

imposition of VAT by Retail Electricity Suppliers;

vi. The installation of WESM compliant metering to all Contestable

Customers (capable of tracking energy transactions in each WESM

interval for purposes of billing and for the settlement of imbalances, line

rentals and net settlement surplus); and

vii. The installation of the IT platform for the B2B infrastructure required for

the business processes which ERC prescribed in the rules for Uniform

Business Practices .

The Philippines will not be the first country/jurisdiction to postpone retail competition because

the necessary conditions for it to function particularly inadequate generation, were absent.

Latin American countries followed a much slower pace than that envisioned in the EPIRA and do

not foresee retail competition at the household level.

6.3.2 STRANDED COSTS

Section 32 of the EPIRA allows NPC to recover stranded contract costs and stranded debts and

DUs to recover stranded contract costs through a universal charge on all end-users. Two


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petitions for the recovery of NPC’s stranded costs were submitted by PSALM to the ERC in 2009.

The first petition is for the recovery of stranded debts estimated at PhP 471 Billion over 17 years

at PhP 0.30/kWh. The second is for the recovery of estimated stranded contract costs

amounting to PhP 22.2 Billion over 5 years at a rate of PhP0.0920/kWh. The petitions are still

under review by the ERC. No DU has filed a petition.

As defined in Section 32, NPC’s stranded debts are any amount of its unpaid financial

obligations net of the PhP200 Billion assumed by the government. Stranded contract costs are

the excess of the contracted cost of electricity under NPC’s and the DUs’ IPP contracts that were

approved by December 21, 2000 over their actual selling price in the market. Market refers to

the wholesale electricity spot market (WESM). In 2007, the ERC issued the ‘Rules for Recovery of

NPC Stranded Contract Costs and Stranded Debts Portion of the Universal Charge’.

Outside the Philippines, the term stranded costs refer to those costs incurred by a utility that

were previously recovered under a regulated regime but can no longer be recovered with the

advent of competition and the removal of price controls.48 These costs were approved or

imposed by the regulator in order to improve the service or hold down rates. Since the new

entrants are not burdened by these costs, competition could result in lower prices and/or the

departure of the utility’s wholesale customers for other suppliers offering lower prices. Either of

these developments mean that the utility will not be able to earn enough revenue to recover its

long-term investments and other costs, which are then stranded. Only generation costs are

stranded . Transmission and distribution costs are not because their tariffs remain regulated.

The bulk of stranded costs consists of generation-related assets; long-term contracts for power

or fuel and regulatory assets that regulators would have eventually allowed the utility to recover

through its regulated rates. The latter includes deferred income tax liabilities, deferred

operating expenses, deferred taxes, unamortized debt expenses, and costs associated with

issuing or reacquiring debt. While there is no agreement, stranded costs are either borne by the

utilities’ departing customers, the remaining customers, or by the shareholders. While the

philosophical debate on recovery has not been settled, the idea that some compensation must

48

See for example Baumol William J and J. Gregory Sidak „Stranded Costs‟ Harvard Journal of Law and Public Policy, Vol 18(3) Summer 1995


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be made had gained ground. The arguments for compensation are premised on economic

efficiency, legal and political considerations the latter to the effect that compensation has to be

made to stop powerful losers from impeding efficient policies.

Applying the internationally accepted definition of stranded cost means that:

a) Only NPC’s generation-related costs are strandable and may be recovered.

Transmission debts absorbed by PSALM do not qualify;

b) Costs that were previously disallowed by the regulator cannot be recovered;

c) Only those approved generation costs that are stranded by deregulation or the

removal of price controls may be recovered;

d) Of NPC’s total generation costs; only those debts and contract costs assignable to

enery traded in WESM , i.e., the spot market volume may qualify for stranded cost

recovery. The amount of stranded costs here shall be the difference between the

assignable costs/debts and trading revenue. However, this does not consider the

possibility that losses were caused by a deliberate strategy to bid low even if

NPC/PSALM could have bidded higher, rather than by market forces;

e) Debts and contract costs assignable to capacities/energy traded or sold outside of

WESM cannot claim stranded costs because their prices continue to be regulated by

the ERC. The TOU prices in the TSC were set by the ERC and prices in the bilateral

contracts will continue to be regulated until open access sets in. Losses incurred

from One-Day Power Sales and similar schemes are business losses , not losses from

deregulation and competition;

f) Debts and contract costs assignable to privatized generating assets cannot be

recovered; except those costs stranded in the WESM prior to privatization; and

g) Debts and losses caused by reasons other than deregulation such as politically

mandated reductions in rates and/or subsidies cannot be recovered.


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Of the total energy traded by the NPC in 2008, only 22% was spot sales. By proportion, only

around PhP0.02/kWh can be claimed as stranded cost if recovery is phased over 5 years as

proposed by NPC. The data provided by NPC do not permit a similar approximation of the

stranded debts assignable to WESM trades.

NPC’s debts are not stranded debts. Many reasons had been given for these debts among them,

subsidized tariffs, regulatory disapprovals for recovery through the approved tariffs,

management inefficiency including “bad” deals, and losses from NPC’s privatization especially

those involving the Administration of IPP contracts. Recovering these debts from the

consumers is without precedent in countries that had similarly privatized their state-owned

electricity assets.

6.4 CONDUCT REGULATION

6.4.1 RATE SETTING METHODOLOGY FOR TRANSMISSION AND PRIVATE DISTRIBUTION

UTILITIES

Transmission tariffs and those of private distribution utilities (PDU) were set through the cost of

service methodology (locally known as Return on Rate Base (RORB) before the EPIRA. The law

allows ERC to adopt other appropriate or internationally accepted rate-setting methodologies

that ensure a reasonable price of electricity and promotes efficiency. The ERC chose to apply

the Performance Based Rate (PBR) methodology, specifically its CPI-X formula to transmission

and PDU tariffs starting in 2003 and 2005 respectively.

In the CPI-X formula, the efficient cost of the utility is pre-determined. Tariffs are increased by

inflation (CPI) but the increase is abated by efficiency savings (X) which is the calculated cost

reduction during the current period from the preceding period. This methodology is most

appropriate where there is potential for large efficiency gains or productive efficiency unlike

the cost of service methodology which assumes that there is not much scope for efficiency

improvement in historical costs. It relies on financial incentives and disincentives to lower


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costs; improve service; and a more rational allocation of risks and rewards between the utility

and the utility’s customers. Its main characteristics are: 1) the linking of regulated rates to

efficient costs and de-linking them from the individual utility’s cost; 2) the reward/penalty

structure; 3) a longer regulatory lag that incent the utilities to cut costs because savings do not

immediately lead to tariff cuts; 4) performance standards so that service quality is not sacrificed

in the cost-cutting effort. The adoption of this formula abroad especially in the UK led to large

efficiency gains and tariff reductions particularly in the first 10 years.

The new ERC methodology is not PBR, much less its CPI-X variant. It is not also an internationally

accepted methodology. It is still RORB with a twist: costs are based on forecasts instead of

historical costs which justifies the consumers’ complaints that they are now financing the

investments and paying the utilities profits on it too; and for nothing. Not surprisingly, it has

resulted in sustained tariff increases rather than deep tariff cuts that characterized its

introduction abroad.

What separates ERC’s new methodology from the true CPI-X formula are:

a) Unbroken cost-price link. Tariffs for the first regulatory period were based on the

utility’s historical cost and for the subsequent periods, on the utility’s own forecast.

The cost forecasts are upwards, never downwards. In contrast, the recoverable

costs in other regulatory jurisdictions are benchmarked to the efficient cost of a

Reference Utility such as in Brazil ,Chile and in other Latin American countires

and/or derived in combination with benchmarking methodologies such as the DEA

and SFA;

b) ‘X’ does not represent productivity gains. There is no prior determination of the

utility’s efficient cost and productivity targets. Thus the “X” or efficiency factor was

0 in the first year of the first regulatory period and a pure mathematical number

that equates the Present Value (PV) of forecast real revenue to the PV of forecast

nominal revenue, in the succeeding periods;

c) No tariff increase abatement by productivity savings. The automatic yearly rate

increases arising from the application of the inflation factor are not abated;


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d) Short regulatory lag. The regulatory lag is shortened to one year since the utility’s

cost and tariffs are reviewed and adjusted yearly. This should have been a

disincentive but is not, since there is no requirement to cut cost;

e) No performance standards. Performance targets have not been set by the ERC

except for distribution systems loss. The utilities’ performance in the most recent 3

years and their own targets are used instead. The utilities are granted an additional

amount in their approved revenue requirement to be used to achieve these targets

or to pay the corresponding penalties to the consumers.

f) Overly generous valuation of the rate base. The rate base is valued by the Optimized

Replacement Cost Method (ODRC) before the start of each regulatory period and

indexed to inflation within the period. This results in excessive gains to the utilities

especially considering that the return on rate base and depreciation account for

55% to 65% of their revenue requirement. Absolute valuation such as through the

ODRC should be limited to the time before a new rate setting methodology is

applied. Thereafter, the rate base should simply be rolled-forward to the succeeding

regulatory period , adjusted for the value of new investments and indexed to

inflation.

6.4.2 NEW RATE SETTING METHODOLOGY FOR ELECTRIC COOPERATIVES

A new methodology was adopted in 2009 that replaced the cash-flow methodology that was

previously used to set the tariffs of the ECs. As shown in Box No. 3, tariffs are group tariffs and

are neither based on the utility’s own historical nor forecast cost but are derived through a

formula that starts from the average operating revenue requirement of the group where the EC

has been assigned. The new methodology is highly arbitrary and has no precedent in the

Philippines or elsewhere. The ERC is now preparing to again change the methodology to one

that is PBR based. The deficiencies found in the PBR for transmission and the PDUs are also

present in the proposed methodology as observed from its latest draft.


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Box No. 3 - New Rate Setting Methodology for Electric Cooperatives

1) Classify ECs into groups according to identified cost drivers,

2) Calculate operating cost per kWh for Distribution, Supply, Metering (DSM) in 2000 by adjusting

each EC’s DSM unbundled DSM in 2000 by the CPI and the average wage increase. Deduct 5% to

net out other revenue income that were included in the 2000 tariff. Set DSM/kWh , the Initial

Standard Tariff (IST) at the median of the groups 2008 operating cost,

3) Calculate Operating Revenue Requirement (ORR) of each group by multiplying the IST by each

group’s 2007 average kWh sale . The derived ORR becomes the basis for calculating the rates per

customer class,

4) Functionalize ORR by using the ratio of each group’s Distribution, Supply and Metering costs to

total cost in 2000,

5) Allocate the functionalized ORR by non-coincident demand for distribution and by the number of

customers for supply and metering

6) Convert the functionalized ORR per customer class to peso.kWh by:

a) Dividing the distribution ORR by the average kWh sales (kW for >240v consumers)

b) Dividing supply revenues vy the average kWh sales (for 220/240v, 10/30 and >240 customers,

divide average number of customers of the group to derive corresponding fixed peso per

customer per month charge)

c) For Residential customer metering charge: first calculate the gross revenue from the

PhP5.00/month metering charge (an arbitrary charge included in the 2000 unbundling

decision) then divide the same by the average kWh sales to arrive at the variable peso/kWh

metering charge. For 220/240v, 10/30 and >240v customers, divide the functionalized

metering per customer class ORR by the average number of customers per month

d) Set the reinvestment fund, i.e. EC consumer-members’ contribution to capital expenditure at

22% of the group’s 2008 median ORR/kWh


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7) Fund capital deficiency with additional contribution of members, to be collected through existing

legal procedures.

Source: ERC ‘Rules for Setting Electric Cooperatives’ Wheeling Rates’ Sept 2009

6.4.3 REGULATION OF NON-PRICE CONDUCT: ERC COMPETITION RULES

Section 45 of the EPIRA directs ERC to formulate rules and regulations to encourage market

development and customer choice and discourage/penalize abuse of market power,

cartelization and any anti-competitive behavior. It specifies that the rules shall define the

relevant markets for purposes of establishing abuse or misuse of monopoly or market position.49

ERC issued the Competition Rules in 2006. The rules cover: 1) prohibited agreements; 2)

prohibition on the misuse of market power ; 3) acquisitions, mergers and consolidations; 4)

clearances and authorizations; 5) disclosure of information; and, 6) penalties. Oddly, it contains

two definitions of ‘market’ as shown below:

“means a market in the Philippines in which electricity or other goods or services

that are directly or indirectly related to or used in connection with the generation,

transmission, distribution or sale of electricity are, or may be, supplied or

acquired” (Definitions)

“ A market includes one in which goods or services, and other goods and

services that are substitutable for, or otherwise competitive with, the first

mentioned goods or services, are or may be supplied or acquired” (Rule 18 (2)

on Interpretation and Application)”50

49

EPIRA Section 45 50

ERC Competition Rules and Complaint Procedures


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The first defines an economic market; not an anti-trust market. The second does embrace the

concept of substitutability, a critical element in market definition, but only refers to the product

market and excludes the geographic market. Section 3 of Rule 18 states that the geographic

area will be considered in determining substitutability but still neglects to define the geographic

market.

Correct market definition is at the heart of competition or anti-trust law. Market power, abuse

of market power, market share and similar competition concepts are all relative to the market.

The Rules also do not clarify these concepts as shown in Box No. 4. As it is, ERC’s Competition

Rules falls short of providing a workable and legally enforceable framework for the evaluation of

anti-competitive conduct. This in turn raises concern over the regulator’s ability to discharge its

responsibility to protect consumers and to create a competitive power market.

Box No. 4 - Excerpt from ERC Competition Rules

Rule 5 – Misuse of Market Power

Section 1. Prohibition. A Person that has a substantial degree of power in a Market shall not misuse

that power. In this Rule, a reference to power is a reference to market power. (NB the Rules does not

define market power)

Section 2. Degree of power; Factors: Without prejudice to the preceding paragraph, a Person is to be

taken to have a substantial degree of power in that Market if:

(a) an Affiliate of a Person has, or two more Affiliates of a Person; or (b) a Person and its Affiliate, or a Person and two or more of its affiliates, together, have a

substantial degree of power in a Market

Section 3. Misuse of power; Factors. In determining whether or not a Person has misused its power in

a Market, the following factors, among others, shall be considered:

(a) that Person would have acted in the way it did, whether or not it had a substantial degree of market power; and

(b) the Person was reasonably justified in using its power in the way it did.

Section 4. Use/Misuse of power; How done. The circumstances in which a Person uses or misuses its

power in a Market may include where that Person:

(a) does an act; or (NB ‘act’ is not described or defined anywhere in the Rules) (b) refuses to do, or intentionally refrains from doing, an act; or (c) makes it known that an act will or will not be done; or (d) refuses to do an act, or to offer to do an act, except on a condition or conditions; or


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(e) makes it known that an act will not be done, except on a condition or conditions; or (f) makes it known that an act will only be done on a condition or conditions.

Source: ERC Competition Rules and Complaint Procedures

6.5 WHOLESALE ELECTRICITY SPOT MARKET

6.5.1 OVERVIEW OF WESM

Objectives and Operating Features

WESM was established to create a fair, transparent and reliable trading environment that will

attract investments and encourage healthy competition that will ultimately lead to cheaper

electricity for all consumers by:

a) Providing incentives for the cost-efficient dispatch of power through an economic merit system while guaranteeing the security and reliability of the power system;

b) Create reliable price signals to assist participants in weighing investment options; and,

c) Provide and maintain a fair and level playing field for suppliers and buyers of electricity.

WESM’s establishment is one of the pre-conditions for open access and retail competition . The

market price in WESM shall be the basis for the determination of the stranded contract cost; i.e.,

the variation between the market price and the contracted price of the quantities transacted in

the market.

Trial Operations Program (TOP) was launched in Luzon in April 2005 and was completed in

December as the last stage of preparation for its commercial operations. A TOP for Visayas was

also launched on October of the same year . Commercial operations in Luzon commenced in

June 26, 2006; in the Visayas, on December 2010.


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WESM is a bid-based energy market only that operates as a gross pool.51 Bilateral contract

quantities transacted in the pool can be settled outside the market. Locational Marginal pricing

(LMP) is applied where settlement is based on the marginal value of all electricity produced

and consumed by time and location at all nodes.

Entities directly connected to the grid are not allowed to inject or withdraw without registering

in the WESM.

Participants

As of December 2010, there were 99 direct and indirect trading participants comprising of 30

generators, 45 distribution utilities and 24 bulk users. The National Grid Corporation of the

Philippines (NGCP) is the network service provider and the system operator (SO) at the same

time. It is also the metering service provider pending the designation of the ERC of separate

metering service providers. Ancillary service providers will be registered prior to the start of

trading of reserves in the market.

Governance

a. Regulatory Oversight

Both the DOE and the Energy Regulatory Commission have regulatory oversight of the WESM.

Together with the Philippine Electricity Market Corporation (PEMC), the three form the WESM

Tripartite Committee as a venue for coordination as illustrated in Figure 21.

The DOE was tasked under the EPIRA to establish the WESM and formulate the WESM rules,

together with electric power participants. It was also mandated by EPIRA to form the

autonomous group market operator (AGMO) thru the creation of PEMC to establish, govern

and initially operate the WESM. To date, the DOE continues to facilitate the development of the

market thru its involvement in the WESM – as part of the DOE Steering Committee and the

Philippine Electricity Market Board.

51

The market is technically an exchange, not a pool, in the absence of side payments.


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The ERC approves the Price Determination Methodology that sets out the principles for the

pricing of electricity at the spot market, the market fees to recover the cost of administering and

operating WESM, and the administered price determination methodology for pricing of WESM

transactions in times of market suspension and intervention. It also sets the criteria for WESM

membership and the performance standards based on the Grid code. As the industry regulator,

its power and authority extends to the enforcement of the rules and regulations, investigation

and action against any WESM participant that violates any law, rule or regulation and impose

fines and penalties for any non-compliance with or breach of the EPIRA, IRR and rules and

regulations in the market.

Source; WESM

Figure 21. WESM Governance Structure


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b. Market Governance

PEMC was incorporated to perform the functions of the autonomous group market operator

(AGMO) as stated in the EPIRA IRR. It functions as the governance arm of the WESM and is

tasked to handle its initial operations until the appointment of the independent market

operator (IMO).

The PEMC Board together with the various WESM committees perform the governance

functions of the PEMC. During the transition period to the selection of the IMO, the PEM Board

is chaired by the Secretary of the DOE. The Secretary also appoints members of the Board. After

the transition period, the Chairman of the Board will be elected by the independent members,

while members will be elected by PEMC members.

6.5.2 PERFORMANCE HIGHLIGHTS

The ensuing review of the market’s performance is based on the results of the Luzon market

operations from July 2009 to June 2010 (and for the full year 2010 when data allows). This

period is a better indicator that those of prior periods because it was at this time that more

private participants entered the market, thus, loosening the control of NPC/PSALM following

the privatization of NPC generating plants and the transfer of IPP energy outputs to private

administrators. The market highlights are: 52

a) Negligible increase in spot quantity accompanied by substantial increase in spot

market value from 2009 to 2010 (Figure 22);

b) High occurrences of pricing errors due to contingency violation of N-1 contingency

and HVDC related concerns. Real-time prices were applied at 60.2% of the time only

(Figure 23);

52

WESM, „Market Governance Updates‟, 4th WESM Annual Participants‟ Meeting, 12 August

2010


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c) Frequent price substitution (Figure 24 and Figure 25) ;

d) Tight supply condition from the Malampaya shutdown; simultaneous occurrences of

forced and scheduled outages; and capacity gap from low capacity offered (Figure

26);

e) Wide price variability ranging from 0 to negative bids (14.5%) to above 10,000

(10.6%) and clustering at the 0-5000 level (61%) (Figure 27 and Figure 28);

f) Highly concentrated when measured on the basis on the actual generation of major

participants net of bilateral contract quantities; (Figure 29);

g) High risk for the exercise of market power by Pivotal Supplier and Price-Setters with

large uncontracted capacities , e.g. (Pagbilao and Kepco Ilijan) (Figure 30);

Source: PEMC

Figure 22. Market Transactions (2009,2010)


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Source: PEMC

Figure 23. Pricing Errors

Source: PEMC

Figure 24. Price Substitution


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Source: PEMC

Figure 25. Supply and Demand Profile (26 June 2009 to 25 June 2010)

Source: PEMC

Figure 26. Monthly Outage Rate By Resource (July 2009-June 2010)


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Source: PEMC

Figure 27. Price Distribution (June 2009 to June 2010)

Source: PEMC

Figure 28. Market Price Trend (June 2009 to June 2010)


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Source: PEMC

Figure 29. HHI Based on Actual Generation Net of Bilateral

Source: PEMC

Figure 30. Combined Pivotal Supplier-Price Setter Index

6.5.3 ASSESSMENT OF WESM


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The market results paint a disturbing picture of a market that is unlikely to deliver on its

objectives to incent efficient generation investments and create efficient price signals without

radical changes in its current architecture and rules. The assessment of the market will

therefore focus on the required adjustments of its architecture and rules as indicated in the

foregoing market results.

Market Architecture

Market architecture refers to the design of component submarkets. They are anchored on the

market structure and are designed prior to the market rules.

The Philippine electricity market is characterized by: (1) tight supply and demand situation ; (2)

increasing dominance of a few large generating groups; and (3) severe transmission constraints

in many zones/nodes. Its operating environment includes political leaders that are inclined to

intervene in the market to deflect mass opposition to high electricity prices.

The tight supply and demand situation means that uncontracted generators possess a high

degree of market power and can exploit this market power through capacity withholding or

excessive price bids. Among the pivotal suppliers and price setters in 2009-2010; Pagbilao’s

uncontracted capacity were approximately 50% while those of Sta Rita and Ilijan were

approximately at 38%. It is interesting to note that these plants are also controlled by the 2 of

the 3 largest groups: the Lopez and Aboitiz groups , respectively. To manage this, there should

be: (a) as an interim measure, high level physical contracting, say, 100% for loads and

consequently, generators ; and b) in the medium term , the introduction of a long-term financial

forward market (forward, futures, swaps, options) that will curb the exploitation of market

power by generators and shield trading participants from spot price volatility. Pending the

operation of the financial hedging market, the spot market is best designed as a balancing

market only to fulfill the contractual commitments of generators and possibly, distributors as

well. This solution is also likely to scale-down government intervention in the market. A

financial capacity market should be created in the longer term with a corresponding

requirement imposed on distribution utilities and large users to contract for a prescribed

percentage of their peak capacity requirements.


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Tight capacity constraints also require the operation of a contract operating reserve market to

maintain system security and reliability and to encourage investments in additional generating

capacity. The pricing of operating reserves is discussed under Market Rules.

Transmission upgrades are critical to relieve transmission congestion. As it is, the market is

characterized by wide price separations among nodes that are only partly managed by the

collection of Settlement Surplus. In the longer term, a sub-market for Transmission Rights (TR)

must be created to manage the trading participants’ exposure to nodal price risks. It can also

do away with Administered Prices, or Price Substitution in cases of transmission congestion.

TRs could be physical or financial (although FTRs classified as options - no payment when the

flow is reversed, are equivalent to physical transmission rights). The market operator (MO) can

periodically auction TRs. Pending the full liquidity of the market, the minimum price of the TRs

can be set by the MO and/or approved by the ERC based on estimates of cost from congestion

and losses.

Market Rules

a) Dispatch Schedule

The current bid-based dispatch schedule is inconsistent with the tight supply situation in the

market. It is a disincentive to generation investments and invites gaming to recover capacity

costs and start-up costs. A cost-based dispatch would have been more appropriate . The current

price distribution in the market shows that many generators are unable to recover their capacity

and start-up costs from their spot transactions . This is likely to result in very high bids in an

attempt to compensate for losses in the spot market. Markets that adopted cost-based dispatch

at the early stages of their operations include Singapore and the PJM . Cost-based dispatch

continues to apply in Chile, Brazil and Argentina.

b) Pricing Errors Notice (PEN) and Market Re-Runs

Real time market outcomes applied 60.2% of the time only. This was attributed mainly to the

high frequency of pricing errors although there were also price substitutions and other


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administered prices imposed by the regulator. When PEN occurs, ex-ante prices are re-run

using ex-post re-run prices. This induces generators to withhold some capacity from the market

because the ex-post prices, by including the must-run units, are almost always lower than the

ex-ante prices. A solution would be to use ex-ante input data instead of the ex-post prices for

the ex-ante re-runs.

c) Must-Run-Units

(i) Dispatch

The planned reserve and energy co-optimization should be implemented without delay. The

current practice of constraining off individual units to provide reserves and interrupting loads to

achieve supply and demand balance could lead to regular under-generation.

(ii) Pricing

Must – Run (MR) contracts are ‘out of market’ arrangements that are necessary for the system

to withstand various contingencies, particularly security and reliability that are beyond the

control of a single generation firm. Must-run generators must therefore be compensated for

their ‘above-market’ costs when they are forced to operate even when the market price is

below their operating costs. These costs include fixed operating costs (that may be scaled

according to contribution to system reliability) ; opportunity cost from foregone energy or

ancillary service revenue; and start-up costs . At the same time, the contract

price/remuneration must be so designed to curb the possible exercise of large market power

held by the units providing the service. This requires that : (1) the opportunity cost not be linked

to market outcomes ; (2) the must-run energy requirements be announced prior to running the

Day-Ahead dispatch schedule; and , (3) Prior to their dispatch as MRU, Must – Run generators

must choose between their declared MR variable compensation or the market price. There

cannot be a “higher of the 2” choice to prevent the MRU from leveraging its market power to

raise prices in the energy or reserve market.

The compensation of MR units have to be formalized in a contract between the SO and the

generators. The contract shall be negotiated and approved by the regulator. It shall contain the

agreed fixed payments regardless of whether or not they are called to run (or scaled down


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according to their contribution) and the generators’ variable compensation when they are called

to run. This variable compensation should at least be equal to the marginal cost of providing the

service.

The current Settlement Procedure of Must Run Units of PEMC53 neither guarantees fixed

payments nor de-link the MRU’s variable compensation to market outcomes. MRUs are paid a

Generation Price Index (GPI) which is simply the average market payment during the relevant

trading interval(s) . Instead of fixed payments, an MRU has to apply for additional

compensation to cover fuel and variable operating and maintenance cost (to include start-up

cost and shut-down costs) if these were not covered in the GPI settlement. Thus, the GPI

settlement could either under compensate or over compensate the MRU its opportunity cost

depending on the market outcome .

d) Regulatory Intervention

(i) Market Intervention and Market Suspension

The WESM Manual on Administered Price Determination Methodology of October 2010

describes the conditions for SO intervention and market suspension by the ERC. Intervention or

suspension occurs when the grid is in extreme state condition arising from: (a) an emergency; (b)

a threat to system security; or, (c) an event of force majeure. It also sets-out the price

determination methodology when market intervention or suspension occurs.

Only the ERC can suspend market operations and when any of the following conditions obtain:

(a) natural calamities; and, (b) declaration of national/international security emergency by the

President. The SO can intervene in the market in an emergency, i.e.; where a situation exists

that has an adverse material effect on electricity supply or which poses as a significant threat to

system security.”54

It is unclear whether prior market suspensions or interventions were mainly motivated by

threats to system security or influenced by high prices. Despite the non-inclusion of “high prices”

53

PEMC „WESM Manual: Management of Must-Run Units” Issue 4, 28 February 2007 54

WESM Rules 6.3.1.1


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as a condition for market intervention, the definition of emergency in clause 6.3.1.1 of the

WESM Rules leaves enough flexibility for the SO and/or ERC to intervene in the market in the

event of high prices. The clause defines emergency as “existence of a situation which has an

adverse material effect on electricity supply or which poses as a significant threat to system

security. The phrase “has an adverse material effect on electricity supply” is ambiguous enough

to allow for such a flexibility. Market suspension or intervention due to high prices curtails real

market price formation that is essential to signal the need for generation investment and dulls

the incentive for such investments. At the very least, the regulatory price cap should be allowed

to work and must be hit in emergency situations caused by insufficient supply. On the other

hand, extra-ordinary price spreads caused by transmission congestion should be addressed by

Transmission Rights instead of market intervention.

Force majeure events are those enumerated in clause 6.7.2 of the WESM Rules: a) major

network trouble that caused partial or system-wide blackout; b) market system hardware or

software failure that makes it impossible to receive or process market offer/bid information or

dispatch the system in accordance with the WESM Rules; and, c) any other event, circumstance

or occurrence in nature of, or similar in effect to any of the foregoing.

(ii) Administered Price Determination

The Administered Price for generators for each generator node shall be the load-weighted

average of the ex-post nodal energy price and metered quantity of the 4 most recent same-day,

same hour trading intervals that have not been administered. In case they were administered,

they will be replaced with prices that have not been administered for the most recent earlier

same or similar day. If prices in these same-day, same hour trading intervals reflect constraint

violation coefficient prices or are subject of a pricing error, the WESM Manual for the

determination of price substitutes for pricing error shall apply.

The base period for determining the settlement amount is too short . An alternative would be

the average of the corresponding prices for the 30 days preceding the market intervention or


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suspension. The methodology for price substitution in cases of pricing errors was previously

addressed.

6.6 SECURITY OF SUPPLY

Security of supply refers to the adequacy of capacity to supply demand and the reliability of

the generation and delivery systems that should result in affordabale rates to end-users55. The

adequacy of supply can be measured in terms of the timely availability of capacity while

reliability is best measured in terms of the risk of interruptions of end-users due to the outages

in the supply (generation) and delivery (transmission and distribution) systems.

The unbundling of generation, transmission, distribution and supply in the restructured power

industry also unbundled the responsibilities for demand forecasting, capacity planning and

project commitment in each sector. The Department of Energy forecasts the demand by Grid

(i.e., Luzon, Visayas and Mindanao Grids) and prepares indicative generation plan in accordance

with the mandate of EPIRA that liberalized the generation sector of the power industry. Unlike

before (i.e., prior to EPIRA) where the National Power Corporation prepared a committed plan,

the private sector is expected to submit to DOE its proposed generation projects with targets or

committed commissioning dates. The Philippine Grid and Distribution Codes prescibe the

forecasting and capacity planning for transmission and distribution networks. The transmission

and distribution utilities prepare the Transmission Development Plan (TDP) and Distribution

Development Plan (DDP), respectively wherein the first five (5) years are committed while those

beyond five years are indicative. From the operational perspective, the transmission company is

mandated by EPIRA to ensure the security of supply (i.e., to ensure that there is adequate

reserve to respond to the outages of generation facilities. The TDP and DDPs are consolidated by

DOE together with the generation plan to form the Power Development Plan.

55

Energy security, according to the International Energy Agency (IEA) is characterized by the energy supply and delivery system that is (a) adequate, (b) Reliable, and (c) affordable. The European Commission defines it as “Uninterrupted physical availability of energy products on the market, at a price which is affordable for all consumers (private and industrial)”


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6.6.1 CAPACITY PLANNING AND PROJECT COMMITMENT

The DOE has a well defined process and timeline in preparing the Power Energy Plan (PEP)

which contains the Power Development Plan (PDP) as mandated by EPIRA (Sec. 37). The PEP

planning process starts in January of each year with the review of the implementation of the

previous year’s plan and in updating policy directions and government commitments. In

February, DOE conducts sectoral planning and coordination meetings internally together with

the attached agencies (i.e., NPC, TRANSCO, PNOC, NEA and PSALM56) to set the key planning

parameters and formulate the initial sectoral simulations. Sectoral public consultations are held

in March to solicit issues and concerns as well as regional and provincial plans. A strategic

planning workshop within the DOE is held in June to present the assessment and draft sectoral

plans/programs with the end-view of resolving conflicting policies. By the first week of July, the

Energy Plan which integrates and harmonize the energy sub-sector assessment, plans and

programs inlcuding supply-demand outlook, investment requirement and legislative agenda is

formulated by DOE. The energy plan is presented within the “Energy Family” and later to the

public for review and comments. The DOE finalizes the Energy Plan by end of July. The final

version of the annual Philippine Enery Plan is submitted to the Office of the President and

Congress on or before September 15.

The planning process for the generation sector assumes that the private sector will respond and

commit to build the generation capacity based on the demand-supply outlook indicated in the

Power Development Plan (PDP). The annual PDP published by DOE since 2001 indicated that

there are enough “committed” generation capacity that will be commissioned to meet the

supply requirements. However, these “commitments” did not translate to actual additional

installed capacity according to the timeline or expected commissioning year. A gap exists

between the generation capacity planning of DOE and the commitment of private generation

developers to build power plants.

Except for a few ECs and PDUs, most of the DUs did not sign bilateral contracts before the

expiration of their TSCs with NPC. Those that signed after a long process of negotiation have

56

Planning documents from DOE indicates that PSALM is considered as an attached agency although by law it is an attached agency to the Department of Finance as it is chaired by the Secretary of DOF


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signed short term (1-3 years) contracts with the new owners of NPC power plants and the IPPAs.

It is also noted that even MERALCO which represent about 70% of the market in Luzon did not

sign new bilateral contracts. Apparently, the Philippine WESM does not really provide an

effective signal to Generators to commit in building power plants for new/additional capacity.

After four (4) years of commercial operation of Luzon WESM that has been indicating the tight

supply situation, there has been no response to the need of the market as no merchant power

plant has been committed by any GENCO. A new capacity which will most likely be added in the

Grid (based on the stage of plant construction) that can be considered as the only real

committed plant by the private sector is covered by long-term contracts, after it was able to

convince small DUs to aggregate their demand.

Based on the contracting and WESM experiences so far, it can be concluded that under the

current capacity planning and project commitment process in the generation sector, the only

modality to ensure the timely availability of new capacity additions is to pursue medium to long-

term (i.e., at least ten years) power supply contracting between GENCOs and DUs.

Unfortunately, the GENCOs perceive the power supply contract approval in ERC as a big risk.

This is evident in the power supply contracts submitted by the DUs to the ERC which include

provisions like “...If the ERC will not approve the Power Supply Agreement, the supplier will not

be obligated to supply...” and “...If the ERC approved a different rates, the Supplier will not be

obligated to supply if the the approved rates will not be financially viable”. The financial closure

with lenders for project financing is now very much dependent on the regulatory approval of

the power supply contracts by the ERC. This issue can be addressed by a government-enabled

and regulator-backed competitive selection process through power supply auctions with a pre-

approved template of power supply contract so that the results of competitive selection process

or auction are not subjected to additional regulatory review.

As to the transmission and distribution sectors, the eventual commitment to build network

capacity is not problematic since the regulatory process assures the investors of recovery and

returns for their investment.


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6.6.2 PLANNING METHODOLOGY AND CRITERIA

The other issue in ensuring security of supply is related to the planning methodology and criteria

used by the respective planners in generation, transmission and distribution. It can be gleaned

from the PDPs published by the DOE that it adopted a deterministic methodology in generation

capacity planning. As shown in Figure 31, the capacity reserve requirements correspond to the

Operating Reserve criteria of the transmission utility (NGCP) which is based on the single outage

contingency criteria, a deterministic approach. Billinton57 emphasized the deficiency of the

deterministic approaches and the need for adopting probabilistic methods in reliability risk

assessments of power systems. Hence, the probabilistic methodology are used all over the

world even by developing countries. The deterministic approaches do not provide consistent

risks assessment because of the probabilistic nature of load variations and forced outages of

plant equipment. In addition, the reliability risks are dependent on the number, type and

capacities of the equipment as well as the size of the power system. For example, the U.S. and

European power systems can adequately address the reliability risks even with less than 10%

reserve margin for an expected one loss of load in ten years while the Luzon Grid will require

30% reserve margin for a one loss of load in one year58.

57

R. Billinton, et. al., “Applied Reliability Assessment in Electric Power Systems”, 1991, IEEE Press. 58

R. del Mundo, Development of Models and Methodology for Optimizing Power System Reliability, University of the Philippines Diliman, 1991


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Source: DOE PDP

Figure 31. Generation Capacity Plan of DOE PDP

It must be noted that prior to EPIRA, the National Power Corporation prepared generation plans

that meets the one day per year (1 day/yr) loss-of-load expectation (LOLE also called loss-of-

load probability or LOLP ) reliability criteria in compliance with the government (NEDA) directive

to adopt the results and recommendations of the value of loss-of-load and power system

reliability study59. Thus, DOE appeared to have digressed when the generation planning was

assigned to them as a consequence of the EPIRA reforms.

The operational reliability criteria for the determination of ancillary services is deficient from the

point of view of capacity planning. It does not take into consideration the scheduled

maintenance outages of power plants. Based on the Open Access Transmission Service (OATS)

and the Ancillary Service approved by the ERC for NGCP, the levels of reserve correspond to

frequency regulating (2.8%), spinning or contingency (10.3%) and dispatchable back-up (10.3%)

which totals 23.4% ; the level of required reserve margin in the DOE PDP as shown in Figure 31.

59

U.P. National Engineering Center, “Optimal Power Supply Reliability for the Philippines”, NEDA TDI No. 53, 1991


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The DOE must use a higher reserve level for the reliability criteria. Based on the 1991 study on

the optimal reliability for Luzon Grid when the demand was about 3,000 MW, the 1 day per year

LOLP correspond to 30% reserve margin. By this time (with about 7,000 MW demand), the

reserve margin would correspond to 25-28% reserve margin. It would be best if a Value of Loss-

of-Load (VoLL) study is conducted which is useful in setting the optimal reserve requirement for

capacity planning and in operating reserve planning. In must be noted that the VoLL is also

required under the WESM Rules which unfortunately is still missing since day 1 of the operation

of WESM.

Pagobo and del Mundo60 reported in their study on the application of probabilistic approach to

establishing spinning reserve for the Luzon Grid that the optimal spinning reserve (for year

2007) should have been only 85% of the reserve requirement established using the

deterministic single outage contingency (i.e., 10.3% of the peak demand). There is therfore an

opportunity to reduce the cost of ancillary services if a probabilistic approach is used. The value

of loss of load used by Pagobo and del Mundo is the inflation-adjusted cost of power

interruptions to industrial consumers in Luzon established in 1991 by del Mundo. It is therefore

recommended that the DOE or NGCP conducts an update to the value of loss of load study in

1991. It is further recommended to the NGCP to adopt the probabilistic approach methodology

in the determination of operating reserves. The ERC can require the NGCP to undertake this in

its submission for the approval and inclusion of rates for ancillary service.

6.6.3 PROVISION OF OPERATING RESERVE

The Operating Reserve (Spinning and Stand-by) is included in the Ancillary Services provided by

NGCP as the System Operator (SO) in accordance with the Philippine Grid Code. These reserves

address the security concerns resulting from forced outages of generating units. While it is clear

that NGCP is responsible for the provision of these reserves, the WESM Rules61 provides that it

60

G. Pagobo, “A probabilistic approach in scheduling spinning reserve based on FOR of Generating Units and the Value of Loss of Load”, MSEE Thesis (2009), University of the Philippines *Prof. R. del Mundo served as MS Thesis Adviser] 61

WESM Rules clause 3.3.3.2 specifies that “The System Operator shall arrange for the provision of adequate ancillary services for each region either: (a) By competitive tendering process, administered by the Market Operator, whereby a number of Ancillary Services Providers can provide a particular category


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must be procured either through contracting or spot market to be administered by the Market

Operator (MO). In the meantime that it is not yet adminstered by the MO, the SO sourced it

from NPC and other interested GENCOs. The experience of TRANSCO then and now NGCP in the

provision of operating reserve indicated that the the actual reserve that were provided are less

than the required level approved by ERC. The experience in 2010 is a classic case of this

problem. There were interruptions due to forced outages of some power plants. To address the

problem of deficient Operating Reserve, the ERC must impose corresponding penalty to the

System Operator if the required reserve was not met or provided by the System Operator.

With regards to the administration of the MO for the procurement of the reserve, the Market

Rules, assumes that the market will automatically provide the reserve. To ensure the security of

the Grid, it is necessary to issue a clear policy that will mandate the System Operator to source

the operating reserve through long-term bilateral contracts (say 90% of required reserve) and

source only a limited amount from the spot market (say 10%). This is similar to the mandate of

the DUs to source 10% from WESM for balancing supply and demand purposes because the

security of supply is supposed to be ensured by new capacities resulting from long-term bilateral

contracts for 90% of the demand. The premise of this policy recommendation emanates from

the fact that trading of energy in WESM did not produce new investment for generation

capacity and so it cannot be relied upon for the Operating Reserve. The long-term contract will

provide security while the short-term trading in WESM of the balancing requirement could

achieve lower cost of ancillary service.

6.6.4 REPLACEMENT POWER FOR MAINTENANCE OUTAGE

The replacement power for generating units maintenance (scheduled) outages are not included

in Operating Reserve because EPIRA envisioned that the Wholesale Competition market design

(with WESM) will automatically lead to “Full Requirements” power supply contract (as opposed

of ancillary services; or (b) By negotiating contracts directly with an Ancillary Services Provider who is a Direct WESM Member, where only one Ancillary Services Provider can provide the required ancillary services; or (c) Where applicable, by competitive spot market trading in accordance with clause 3.3.4.


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to the (Generaing Plant-contingent PPA).62 Unfortunately, the contracts signed by DUs with

GENCO’s for new generating capacities (e.g., GNPower in Luzon and KEPCO and SALCON in the

Visayas) indicated that the GENCO’s are excuse to supply during plant outages (maintenance or

forced) as well as with some new owners of the privatized NPC plants. There is no security

problem for the forced outages because it is covered by Ancillary Services. However,

maintenance outage allowances in these contracts creates a risk for the DUs as they face either

high market price or even lack of supply for the replacement power. Unfortunately, in the same

contract, the GENCO’s have taken advantage of the market design wherein they can supply from

other power plants or from WESM (at their discretion). This is a clear case of selective

application of contract provisions from “Purchasing Agency or Single Buyer Market” model to

“Wholesale Competition” market model. The power purchase agreement (PPA) of IPPs is

applicable basically to a the Single Buyer market since as the Single Buyer has the portfolio of

power plants to manage forced and maintenance outages. The PPA which is plant-contingent

contract does not work to multiple-buyer market. This may apply to MERALCO because it is

virtually a Single Buyer in Luzon because of its market share. But this will definitely not work in

the context of small private DUs and Electric Cooperatives. The DOE or ERC must issue a policy

directive or rules and regulation that power supply contracting under EPIRA shall be “Full

Requirements” contracts and “Plant-Contingent” contracts are not allowed.

62 “Full Requirements” contracts obliged the seller (GENCO) to supply 24/7 the buyer (DUs) in

accordance with the agreed demand specified in the contract. The seller is not obliged to supply its customers from its generating plants. Plant-Contingent Power Purchase Agreements (PPA) of IPPs obliged the seller to supply only from the seller‟s Power Plants. Hence, they are excuse during maintenance outages.


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7 ASSESSMENT OF INSTITUTIONAL GOVERNANCE FRAMEWORK The preceding review of the achievements of the EPIRA and the assessment of industry

regulation do not paint a flattering picture of the state of the industry’s regulatory governance.

The core contents of regulatory governance are: (1) the objectives and functions of regulation ;

and, (2) the specific institutional framework or the design aspect of regulation. The first was

reviewed in Sections 2 and 3 of this report. This part will assess the second.

7.1 OVERVIEW OF INSTITUTIONAL GOVERNANCE

The immediate institutional governance framework of the Philippine electric power industry

comprise of: (1) the ERC, as the regulator; (2) the DOE , as the policy body; and (3) Congress

through the Joint Congressional Power Commission as the oversight body. Decisions of the ERC

can only be appealed to the Court of Appeals and ultimately, to the Supreme Court. This

structure is presented in Figure 32 below.

Figure 32. Governance Structure of the Philippine Electric Power Industry


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7.2 APPRAISAL OF INSTITUTIONAL GOVERNANCE

The study applies the criteria developed by Stern and Holder for the assessment of the

performance of regulatory systems in the developing countries in Asia.63 The criteria include:

a) Clarity of Roles and Objectives;

b) Autonomy;

c) Participation;

d) Accountability;

e) Transparency; and

f) Predictability.

7.2.1 CLARITY OF ROLES AND OBJECTIVES

This refers specifically to the clarity of the roles and responsibilities between the policy making

and regulatory agencies. Clarity is essential to enhance accountability and predictability in the

regulatory process.

The EPIRA clearly delineates the roles of the DOE and ERC. The latter has exclusive authority

over rates and as detailed in Section (43) has principal responsibility for consumer protection by

promoting competition; encouraging market development; ensuring customer choice and by

penalizing abuse of market power . The DOE is mandated to ensure the proper implementation

of the EPIRA. In addition, Section (37) mandates it to:

a) Ensure the reliability, quality and security of electric power supply;

b) Facilitate /encourage reforms in the structure and operations of distribution utilities;

c) Develop policies and, where appropriate, promote a system of incentives for

adequate and reliable electric supply including reserve requirements;

63

Stern John and Holder Stuart “Regulatory Governance: Criteria for Assessing the Performance of Regulatory Systems, An Application to Infrastructure in Developing Countries of Asia”, May 1999


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d) Establish the WESM;

e) Develop policies and programs for energy efficiency;

f) Formulate and implement programs for the development and commercialization of

non-conventional energy systems;

g) Encourage private sector investment in the electricity sector; and

h) Promote the development of indigenous and renewable energy sources.64

The DOE Secretary is also directly responsible for total electrification as Chair of the National

Electrification Administration.

Notwithstanding the clear delineation in the EPIRA, the DOE largely relinquished its role, leaving

most matters in the hands of the industry participants and to the ERC. The associated

consequence was that the ERC did not have much policy guidance for its regulatory decisions

and attempted to fill the void by regulation. A specific example is the adoption of the new rate

setting methodology for the ECs. The new methodology is an attempt to address the chronic

financial instability of the ECs in the absence of effective DOE policy initiatives to stabilize their

financial situation. With respect to the encouragement of private sector investments; the

Department has not gone beyond the customary investment missions and fiscal incentives when

it could have initiated an in-depth examination that could have led to the identification of

weaknesses in the contracting process as a disincentive to investments. The DOE points to a

number of factors as being constraints on its ability to effectively perform its responsibilities

under the EPIRA.65 These factors include the ERC’s insistence on its independence which

constraints the DOE from taking the initiative to design policy and undertake programs to

address the industry’s problems; (a view, incidentally, shared by many in the industry), limited

in-house capability (based in large part on its lack of funds to hire additional staff) and the

reported lack of police power to enforce its decision to undertake non-price regulation that are

64

EPIRA, Section 37 65

Based on interviews by a member of the study team with DOE officials for a prior ADB study


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outside the ERC’s authority notwithstanding Section 37 (p) and (q) that explicitly vest the

Department with such powers.66

7.2.2 AUTONOMY

This pertains to autonomy from political interference and equally importantly, to security of

tenure and financial autonomy. The ERC does not enjoy financial autonomy because its budget

must be approved by Congress through the regular budgetary process. Almost 65% of its budget

are for salary and personnel expenses. This does not leave much for staff training and to raise

salaries to the level of the regulated utilities’ to attract high quality staff and reduce employee

turn-over. Instead, the agency is dependent on external consultants that are mostly packaged

with the technical assistance provided by bilateral and multilateral agencies. The annual

appropriation may be augmented if its collection from supervisory, licensing and other fees

exceed its revenue target that is set by the government; e.g.; at PhP300 Million for 2009. This

process has resulted in a perverse incentive to collect varied and increasing fees from industry

participants that are eventually passed on to the consumers.

The ERC is an independent body that is legally free from government interference. The

Commissioners have security of tenure. The prevailing opinion is that it has taken its

independence to the extreme, i.e.; in a manner that precludes coordination with other

executive agencies and meaningful consultations with industry stakeholders.

7.2.3 PARTICIPATION

Meaningful participation by all stakeholders is required to improve the quality of regulatory

decisions and to increase the likelihood of support from the regulated entities, consumers and

the general public. The ERC’s process achieves the opposite effect and is costly to both the

utilities and the consumers. It is a litigious/rule making approach that requires petitioners and

oppositors to hire lawyers; limits the participants to petitioners, accredited oppositors and

66 Sections 37 (p) and (q) authorizes the Department to “formulate such rules and regulations as may be necessary to implement the objectives of this Act” and “exercise such other powers as may be necessary or incidental to attain the objectives of this Act”.


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intervenors; and, limit itself to considering the ‘facts’ of the case and avoids the consultative

and iterative approach adopted in other jurisdictions (e.g. UK, Australia, UK) where debates are

encouraged and a broad range of comments are invited and heard. The ERC claims that its

process is called for by the quasi-judicial nature of its decisions notwithstanding that other

quasi-judicial entities in the country and in the United States (from where the process was

borrowed) undertake wide ranging and non-legal consultations . Aside from being the result of

the regulator’s narrow interpretation of the quasi-judicial process, the litigious process could

be a reflection of its limited capacity to undertake comprehensive economic and technical

evaluations to support its decisions.

7.2.4 ACCOUNTABILITY

Accountability depends on the availability of an effective mechanism to challenge regulatory

decisions. The current appeal mechanism – where appeals could be decided by the ERC and/or

the courts anywhere from 1 to 5 years does not induce accountability.

7.2.5 TRANSPARENCY

A transparent regulatory framework requires the regulator to explain and justify its decisions

and processes in a manner that leads to a clear understanding by all participants of the rules of

the game.

Section 21 of the EPIRA on Reportorial Requirements requires the DOE to submit to the Joint

Congressional Power Commission (JCPC) a semi-annual report on the law’s implementation.

The ERC’s report to the DOE is submitted to and integrated by the DOE in this report. The final

report is published in the DOE website.

The ERC also prepares an Annual Report that is published on its website. The Annual Report and

the report to the JCPC detail its accomplishments in the past year and the related pending issues

concerning its ongoing work. Feedbacks to the DOE and ERC reports are seldom received from

the JCPC.


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The ERC’s decision-making process is fairly transparent as the regulator regularly publishes on its

website its rules and decisions with their corresponding reasons. However, stakeholders,

particularly consumers, complain that the attachments to rate applications that provide the

basis for the rate petitions are not published in the website and are not easily accessible at the

ERC contrary to the latter’s claim that they can be easily reproduced for a fee. Even the utilities

complain that they are not given access to the ERC’s computations/calculations that form the

basis of the rate decisions and adjustments in the terms of the power supply contracts that are

submitted for approval.

7.2.6 PREDICTABILITY

A predictable regulatory framework precludes regulatory opportunism and/or sudden changes

in the over-all legal framework. It does not necessarily mean being welded to set legal

precedents to the exclusion of unique economic and technical factors attendant to a case.

Industry stakeholders and observers claim that ERC decisions are either too predictable or too

unpredictable. Decisions on tariffs, capital expenditure and similar issues are criticised for

failing to take into account differences in operating situations of the utilities. For instance,

stakeholders observed that the ERC appears to have a pro-forma decision where only the

numbers and the name of the utility are changed (and, in one or two rate decisions, it even

neglected to change the name). On the opposite end, generators and distribution utilities

cannot predict how the ERC will rule on their power supply contracts. It was also observed that

the decisions and/or rules are rarely accompanied by considerations/evaluations of their

economic, financial and technical merits.


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III ANALYSIS OF INTERNATIONAL MARKETS


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8 PURPOSE OF ANALYSIS OF COMPARABLE INTERNATIONAL

MARKET

The analysis of international markets is intended to enrich the study by providing a model for

the design of policy reform and empirical evidence for or against certain policies under

reasonably comparable circumstances. To that end, the study analyzes the experiences of Chile

and Brazil with respect to the:

a) Characteristics and issues of the industry prior to reform;

b) Institutional framework including legacy economic policies and political structure;

c) Approach to and design of the reform;

d) Key elements of the reform process as regards to incentives and governance;

e) Defining features and characteristics or best practices; and

f) Policies to address specific issues relating to generation investments.

Aside from having the longest running and most comprehensive electricity reform after WWII,

Chile’s reforms which started in 1982 are widely acknowledged to be highly successful and a

model for developing countries around the world. Chile has been in the forefront of innovation

in the creation of electricity markets. Brazil on the other hand has the largest electricity market

in South America. Capacity addition had lagged behind demand growth before the reforms.

These two countries have the highest access rates in Latin America. From a policy and regulatory

perspective, it is helpful to have a good understanding of how their energy sector copes with

such an increase in demand. While Chile’s electricity system shows that effective competition

and privatization is possible in a relatively small market, Brazil’s illustrate that it is possible in a

large developing market. Their combined experiences and lessons learned are highly instructive

for developing countries like the Philippines that are still grappling with electricity reforms.


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9 CHILE’S ELECTRIC POWER INDUSTRY

9.1 OVERVIEW OF ELECTRIC POWER INDUSTRY OF CHILE

Chile’s power sector is organized in four (4) grid systems, namely:

a) Sistema Interconectado Central (SIC), the Central Grid, which serves over 90% of the

population and covers more than 40% of the country’s area;

b) Sistema Interconectado Norte Grande (SING), the Northern Grid, which is mainly

thermoelectric and serves mostly the mining industry in the region that accounts for 98%

of the system’s demand ;

c) Aysén and Magallanes Grids, which are both located in the extreme south of the country

and serve the remote areas. The combined capacity of both grids represents about 1%

of Chile’s total generation capacity .

The power sector consists of four private players that interact in the supply chain: Generation,

Transmission, Distribution Companies, and Clients. Generation companies produce the energy

using different sources (hydroelectric, coal, gas, diesel, wind ) that are sold to distribution

companies and non-regulated clients or consumer with consumption greater than 2,000 kW.

Regulated clients are obliged to buy electricity from a distribution company while non-regulated

clients can buy power and energy from any generation or distribution company.

The structure of the installed capacity is shown in Figure 33. The hydro capacity is very variable

due to periodic draughts. During very wet years such as in 2002, the energy supplied reaches

53% of the national load. During dry years such as in 1999 , it supplies only about 36% . The

generation profile per technology is shown in Figure 34.

An independent entity, the Economic Dispatching Center (CDEC) coordinates the operation of

the systems. CDEC ensures the efficiency, security and sufficiency of the power supply in

compliance with applicable regulations. It also calculates the payments between generation,


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transmission and distribution companies. Its board is composed of the representatives of the

generation and transmission companies and non-regulated clients.

Figure 35 illustrates the structure of the Chilean electrical market.

SIST

EMA

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30%

40%

50%

60%

70%

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5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 (*)

Part

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EMBALSE PASADA GAS

GNL CARBON-PETCOKE CARBON

DESECHOS DIESEL FUEL

DIESEL-FUEL EOLICA Participación Carbón

Participación Hidroeléctrico Participación Gas Natural Participación Diesel

0%

10%

20%

30%

40%

50%

60%

70%

80%

0

2,000

4,000

6,000

8,000

10,000

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16,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 (*)

Part

icip

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ene

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(G

Wh)

EMBALSE PASADA GAS GNL

CARBON-PETCOKE CARBON DESECHOS DIESEL

FUEL DIESEL-FUEL EOLICA Participación Carbón

Participación Gas Natural Participación Diesel

0%

10%

20%

30%

40%

50%

60%

0

10,000

20,000

30,000

40,000

50,000

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 (*)

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EMBALSE PASADA GAS

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DESECHOS DIESEL FUEL

DIESEL-FUEL EOLICA Participación Carbón

Participación Hidroeléctrico Participación Gas Natural Participación Diesel

Legend Gas Natural- Natural Gas

Carbón – Coal

Biomasa - Biomass

Eólica – Wind Power

Embalse – Hydro (reservoir)

Pasada- Hydro (run of the river)

Derivados del Petroleo – Oil Derivatives


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Source: CNE

Figure 33. Energy Production in the Chilean National Grids


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Figure 34. Generation Profile Per Technology in Chile

Pasada13 MW

0.4%

Carbón1,138 MW

31.8%

Gas Natural2,074 MW

58.0% Diesel131 MW

3.7%

Derivados del Petroleo217 MW

6.1%

CAPACIDAD INSTALADA SING

Pasada1,592 MW

10.8%

Embase3,706 MW

25.2%

Eólica81 MW

0.6%

Biomasa

58 MW0.4%

Carbón2,137 MW

14.5%

Gas Natural5,050 MW

34.3%

Diesel

1,707 MW11.6%


2.6%

CAPACIDAD INSTALADA TOTAL

Pasada1,580 MW

14.2%

Embase3,706 MW

33.2%

Eólica81 MW

0.7%

Biomasa58 MW

0.5% Carbón

999 MW9.0%

Gas Natural2,976 MW

26.7%

Diesel

1,576 MW14.1%


1.5%

CAPACIDAD INSTALADA SIC


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Figure 35. Chilean Electricity Market Structure

9.2 INDUSTRY RESTRUCTURING AND POLICY REFORMS

9.2.1 KEY ISSUES PRIOR TO REFORM

The difficulty of securing project financing in the 1930s caused the industry to stagnate. The

government took up the slack left by weak private sector interest and eventually ended up

controlling the industry by the 1970s. A non-adjustable pricing scheme was established. The

resulting prices did not cover operating costs much less the capital costs of the investments. The

losses of the vertically integrated electricity companies were simply absorbed by the State.

Tariffs were eventually allowed to rise between 1974 and 1980. This stabilized the financial

situation of the State companies but was by itself insufficient to solve the problems that plagued

the industry; namely:

a) Inefficiency. Being state companies, their structures were large, complex and

somehow difficult to control. The investments were planned according to technical

criteria that often neglected economic considerations;

b) Flawed Pricing Policy. Tariffs were not based on the efficient cost of delivering the

service but on actual cost incurred by the utilities. The lack of a standard and

uniform rate setting methodology led to differential pricing among the utilities and

discrimination among client categories. High inflation in the seventies resulted in

Transferencias aCosto Marginal

Empresa

Distribuidora

Empresa

Distribuidora

ClienteLibre

ClienteLibre

Cliente ClienteCliente Cliente

G G

CDEC

Marginal Cost Transfers

Distribution

Company

Distribution

Company

Free

clientFree

client

Free client FreeClientRegulated Client

Node Price

Node price

Free price

Node Price

SPOT MARKET

Zona

Concesión

Free

PriceFree

Price

Regulated Client

Node Price


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tariffs that were far below the amounts needed to recover investments. The Tariff

Commission progressively lost its influence over the tariff setting process and the

task of conducting pricing studies was eventually taken over by the National

Commission on Energy.

c) Huge Financial Drain on the State Coffers. By 1979, the State owned 90% of

generation, 100% of transmission and 80% of distribution. The losses incurred by

the State-owned power companies meant that minimal funds were left to maintain

and provide quality service to the industry’s customers.

9.2.2 INSTITUTIONAL BACKGROUND , KEY OBJECTIVES AND ELEMENTS OF THE

REFORM

Reforms were started in 1982 and carried out in a dictatorial regime thus limiting consultation

and opposition from affected stakeholders such as the remaining private operators, prospective

investors and consumers.

The principal reform objective was to privatize the industry. The process was strongly influenced

by the prevailing market ideology of the University of Chicago whose disciples were the prime

mover of the reform process. The reform succeeded in creating a vibrant private industry but

left lingering structural and institutional weaknesses that remain to be addressed.

Those weaknesses are partly explained by the origins of the reform, such as the decisions on

privatization as well as price risks that mainly represent the national electrical system. The

energy price risk is directly related to the highly varying hydrology. Frequent droughts also

caused huge increases in marginal costs due to the need to replace the hydro power with high-

cost generators such as diesel.

One major factor to consider in the privatization effort is the presence of ENDESA, the largest

generating company of the system plus the water rights that were granted to it. This company

also has ownership links to one of the biggest distributors in the country. A really powerful

entity was created against whom others, particularly new entrants were at a competitive


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disadvantage. Due to the importance and size of ENDESA, it is very difficult to legislate on

topics that could go so far as to harm it.

The General Law of Electric Services that was passed in 1982 unbundled and privatized the

industry. The law introduced a liberalized market in generation and third-party access to the

transmission network, setting up a system operator to coordinate the operations of competitive

generators. The privatization process began in the 80s and was completed in 1998 when the last

state-owned utility was privatized.

From the beginnings of the reform, the main investment incentive element has been the

establishment of prices that reflect the true costs of providing the service. This was

complemented by the provision of a transparent and stable regulatory framework for the

industry.

The regulatory commission, National Commission of Energy (CNE) that was created in 1978 was

charged with the development of a regulatory environment conducive to the efficient

development of the industry and to prepare for its privatization. CNE was provided with wide

government support. Its managing board is comprised of 7 of the 21 state ministers, namely: the

Secretary of Defense, of Treasury, of Economy, of Planning,, of Mining, the Presidency

Spokesman and the presiding minister of the board who is a member of the armed forces.

9.2.3 POLICY AND REGULATION OF GENERATION

The policy and regulatory framework for generation are contained in two laws, as follows:

a) General Electric Services Law or DFL N°4 from 2004, LGSE (for its Spanish

acronym); and

b) ERNC Law or Law N°20257 which requires that 10% of consumed energy comes

from renewable sources.

DFL N°4 Law grants private generators complete freedom in their investment and marketing

decisions within the pre-established rules. Any generator with more than 9 MW of installed


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capacity has the right to access the Energy Spot Market and can buy and sell energy regardless

of its installed generating capacity. There is no electricity broker in Chile’s electric power

market.

Generation companies have two kinds of incomes for its business: Capacity Payment and Energy

Income.

The capacity payment is calculated on a monthly basis (US$/kW/month) as the base payment

plus the fixed operation costs of a reference gas turbine. This payment is calculated by CNE and

applies to the firm power available from a unit to cover the 8 peak load hours of the winter

period. The winter period goes from April 1st to September 30th. The capacity to be considered

for capacity payments is calculated taking into account the availability of each unit:

a) For hydro units, it considers the power they are able to supply during 8 hours per

day in the winter period of the driest hydrologic condition registered in the past 40

years. As a result of this calculation, the capacity finally paid (firm capacity) varies

between 50% and 70% of the installed power for these types of units;

b) For thermal units, calculation takes into account typical unavailability values. The

capacity paid (firm capacity) varies between 70% and 85% of the installed power;

c) Thereafter, each calculated firm capacity is adjusted by a unique coefficient in a

way that the sum of all the firm capacities will be equal to the peak load forecasted

for the year. These calculations are performed ex ante, at the beginning of every

year by CDEC, therefore the firm power of each unit is independent of its real

production during the year;

d) The power withdrawn by the generators in the peak load period to meet their

contracts is compared with the firm power of its units. If there is a deficit, the

generator is seen as a buyer of this power in the spot market in that year and has to

pay the power deficit in 12 monthly payments. If the generator had surplus power,

then it is considered as a power seller in the spot market and receives every month

the appropriate payment. The balance of purchases and sales of firm power is


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performed at the beginning of the year based on estimations of its withdrawals at

the peak load hours. This balance is recalculated once the peak load has happened

and then a re-settlement is performed;

The Energy incomes come from different sources:

a) Energy sales to the Spot Market;

b) Energy sales to distributors companies through open and competitive bids;

c) Energy sales to non-regulated costumers, by means of freely established contracts for consumers with demand over 2000 kW; and

d) Energy sales by means of freely established contracts with others generation companies;

Energy Sales to the Spot Market

The Spot market operates as a balancing market for generators only. Distribution companies

and non-regulated costumers do not have access to the Spot Market and can only buy energy

through supply contracts.

Generators are allowed to sell their uncontracted capacities and to buy for their contracted

commitments. The spot market price or the hourly marginal cost are the variable costs of the

most expensive unit in operation. In the event of energy shortage or rationing, the marginal cost

becomes the default cost of the system.

The market is operated by the Economic Dispatch Centers (CDECs). Each CDEC plans the

operation of their respective systems in the medium and short term; draws up the real time

dispatch schedule of the generating units; determines the system’s marginal cost and makes up

the payments between generators companies.

The generation units’ dispatch are centrally planned by each CDEC using optimization models to

get the lowest operational cost of the system subject to security and quality of service

restrictions. Each hydroelectricity generator informs the CDEC of the dam levels and tributary to


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its run by the river plants. Thermoelectric generators are required to report their operating

costs. The reported costs could be audited by the CDEC. The CDEC calculates weekly or at any

time that it is necessary, the value of water levels at the dam and determines the hourly

dispatch for the following day and by block for the incoming week. It then determines the hourly

energy Spot Price of the system or the system marginal price (SMP) and calculates the energy

transfers between generators that is valued at the Spot Price. The pay settlements are made

directly between the generation companies without the intervention of the CDECs. Generators

are paid only when they are dispatched. Payments represent the difference between energy

withdrawn for the generators’ contract commitments and the energy sold to the market.

Energy sales to distribution companies

Distribution companies must contract for the requirements of the regulated market, i.e. those

with demand lower than 2000 kW. The energy tariff for this market was historically regulated

and fixed at the node price. However since 2010, the energy and power prices had been

determined by auction where the distribution companies bid the required supply for their

regulated customers’ consumption. The tenders are public, open, non-discriminatory,

transparent and are supervised by the regulator, CNE, the Fuel and Electricity Superentindence –

SEC and the Economic Prosecutor.

The main characteristics of the auction are:

a) The bidding terms are developed by the distribution companies subject to the

approval of the CNE. The quality and safety conditions of service will be unique to all

the bidders who can offer special qualities of service or additional benefits in the

provision of energy tendered;

b) The contract duration must be specified in the bidding document and shall not

exceed 15 years. Offers of supply for periods less than or greater than those

indicated in the bid terms are not accepted. CNE prescribes the maximum amount

of energy that a distributor can contract in each contract and the maximum amount

to be contracted per year.


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c) While bidders can bid any price, contract prices are capped at the current node

price plus 20%. If the bid fails, a rebidding can be held 30 days later at which time

the CNE may authorize an increase of up to 15% of the price cap. The node price is

the price at the date of the tender.

d) The bidder should show the change from their base bid price from the application

of the price indices. The indexing mechanism should reflect the variation of the

investment cost of the generating units. The allowable indices are pre-defined and

are common to all bidders. Bidders are free to assign the weight factors for each

index in their bids;

e) The contract is awarded to the bidder offering the lowest price of energy;

f) Prices obtained in the bids are established through a decree that contains the basic

price and the indices for the duration of the contract;

g) The indexed bid price is passed on by distributor to its final customers. The pass-

through price of each distribution company cannot be higher or lower than the

average price of all contracts in force ±5%; and

h) In the event that a vendor submits an average price that exceeds the 5% limit, the

average price of the distributor is adjusted downwards to this limit. The difference

in revenue generated by the adjustment will be prorated among all regulated

customers in the distribution systems. The resulting reassessments will be settled

between the distributors.

Energy sales to non-regulated costumers

Sales to customers with more than 2000 kW of demand are not subject to price controls.

Generally, clients with less than 20 MW demand are still supplied by distribution companies.

The competition for non-regulated customers is tough.

The prices for non-regulated customers were previously lower than regulated prices. This

changed in the last 4 years because of higher spot market prices that were passed on by the


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generation and distribution companies to their non-regulated costumers. This pass through

system will be allowed until 2013 when the prices in the Power Purchase Agreements will be

actualized with the variations of coal prices and CPI, among others.

Energy sales to other generation companies

Generation companies contract with other generators to mitigate their risks. For example, a

generation company with a high hydro percentage in its generation mix and a high contract

volume could enter into a contract with a thermoelectric generator for back-up capacity in order

to reduce its costs in the event of non-favorable hydrological conditions such as drought.

Contracts between generators are expected to increase with the passage of the Non

conventional Renewable Energy (ERNC) Law in 2010 . Non-RE generators are expected to

contract for the 10% RE obligation mandated by the law.

Policy and Regulatory Incentives for Generation

The CNE prepares an indicative plan for generation expansion for the next ten years. This plan is

critical to new generation investments because the inclusion of a proposed power generation

project facilitates the obtaining of the project finance. This plan was the reference point for the

calculation of node prices prior to the adoption of the auction system for supply contracts.

A specific investment incentive mechanism that was in place since the beginning of the reform

until the year 2004 was the “failure cost”. This was the price for the energy transfers between

generators in cases where the installed generation capacity was insufficient to supply the total

demand of the system and was fixed by the regulator. This mechanism was intended to

incentivize generation adequacy by equating prices to the scarcity cost or its economic costs.

Generators in deficit who had to buy energy from others with surplus capacity had to pay at

these high prices thus encouraging investments in backup generation. Nevertheless, this

mechanism was not enforced during the energy deficit period that was caused by extreme

drought. This motivated a modification of the law to harden the terms of the obligation but had

an unwanted effect: the generating companies avoided signing supply contracts with the

distributors because of a negative risk evaluation. This situation was aggravated by the

curtailment in the supply of natural gas from Argentina that caused uncertainty over the choice


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of generation technology to invest in. The crisis motivated another amendment to the law that

obliged distribution companies to auction long-term contracts for their energy requirements.

This competitive tendering process has proven to be more effective in attracting new generation

investment than the Indicative Generation Plan.

Before 2005, the generators were not interested in contracts with distributors as the investment

in coal, wind, hydro or geothermal plants were threatened by the possibility of recovery of the

gas importations from Argentina. Assuming this was the case, then the non-gas plants would not

have been competitive and the regulated prices would have gone down (as the regulated prices

were then calculated as the weighted average of the marginal costs for the next 48 months).

The success of the auctions implemented in 2005 in enhancing the generators’ investment is

due to the indexation system. In that system, the generators can choose an indexation based on

combinations of the fuel price variations and the CPI.

The indexation system resulted to a huge improvement in the investments generating a large

portfolio of projects as summarized in Table 28.

Table 28. Investments for New Generation Projects in Chile

TECNOLOGY QUANTITY POWER

PROJECTS MW Coal Thermal plants 29 7600

Hydro Power Plants 38 12100

Wind Power plants 18 1260

Geothermal Plants 14 540

TOTAL 21500

It has to be noted that not all those projects have been constructed nor are currently being

constructed as the legal and environmental processing is extensive and complex. This

significantly affects the timing of the projects, sometimes causing indefinite postponement. This

situation specially affects coal plants as well as the hydro plants with reservoirs.


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Prior to the implementation of the auction system, there were no generation deficits due to the

contribution of small investors that installed emergency generation equipment (diesel engines

and turbines). Those investors were motivated by the capacity payments and the possibility of

obtaining high marginal prices (which actually happened in the period previous to the

international economical crisis). The downside was high electricity prices because of the high

cost of operating these plants.

9.2.4 POLICY AND REGULATION OF TRANSMISSION

The transmission system in Chile is divided into 3 categories: the Trunk System, Sub-

transmission System and the Additional System. The Additional System is composed of the

transmission facilities, lines and power substations that are primarily intended to transmit

electricity to non-regulated costumers and other end-users for which the generators are

allowed to inject energy to the interconnected system without being part of the Trunk System.

DFL N°4 mandates open access to the transmission system. However, open access to the

Additional System is limited to the transmission facilities that use national properties. The

transmission charges for the Trunk and Sub-transmission systems are determined by the CNE

and valued by the CDECs who inform the companies of the amounts that they must pay. Tariffs

are fixed for a 4-year period. Payments for the use of Additional system lines are negotiated

between the owner and the user.

The law limits the participation of generators, distributors and consumers in the ownership of

the trunk system. The individual participation, directly or indirectly, of companies operating in

any other segment of the electrical system or of users who are not subject to price fixing in the

main transmission system may not exceed eight percent (8%) of the total investment value of

the main transmission system. In addition, the sum of the individual participation of generators,

distributors and non-regulated costumers in the ownership of the trunk transmission system

shall not exceed forty percent (40%) of the total value of the trunk system.


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The income that transmission companies receive for their existing installations corresponds to

the annuity of the investment value (AVI) plus operating, maintenance and administration costs

(COMA). The annuity of the investment value of existing facilities is calculated using a discount

rate of 10% in real terms (before taxes) and an economic life of 30 years.

Payment for new facilities in the trunk systems is equal to the bid of the winning bidder in a

competitive tender. The expansion of existing facilities is assigned to their respective operators

and is paid as a function of their declared investment value during the bidding for their

construction.

For the Sub-transmission systems, the Annual Investment Value (AVI) and the Annual Operation

and Maintenance Costs (COMA) are determined in quadrennial for each demand adapted

system.

The privatization of the transmission sector acted as a catalyst for new investment that was

reinforced by a tariff process that ensured cost recovery and a fair return on investments.

Both the Trunk and Sub-Transmission systems are subject to price controls. Prices are

determined in quadrennial studies that consider demand projections and new generation

investments. The study, which is undertaken by private and independent consultants determine

the tolls to be paid for the use of the facilities; which power lines or substations shall be

upgraded; and/or, if new facilities are needed. The toll is a function of the level of investments;

the operation and maintenance costs of the facilities, with a 10% average cost of capital over an

economic life of 30 years.

These studies are reviewed and approved by a special commission whose members are drawn

from the electricity industry and from the government. The construction of facilities that are

declared as essential for the operation of the transmission systems goes through an

international tender. The tolls to be paid for the use of the new facilities are based on the

results of the bidding processes.


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9.2.5 POLICY AND REGULATION OF DISTRIBUTION

The authority to construct and operate a public distribution network is granted through an

indefinite nature concession that obliges the concessionaire to provide service to anyone who

requests for it. The concession could be terminated in case of repeated poor service.

Distribution companies must have supply contracts with generators to supply their regulated

customers for at least the next three next years. This contract is the result of the bidding process

explained previously in this document.

The electricity tariff that apply to regulated customers consists of the prices of energy and

power that unifies generation (energy and power), transmission (high voltage line and

substation use) and distribution (medium and low voltage line and substation use) costs. The

distribution charge is determined by the Distribution Annual Value (VAD). The VAD is calculated

as the capital, operating and maintenance costs of an efficient distribution utility, with density

characteristics comparable to the utility to whom the distribution charge will apply. Therefore,

the distribution tariff under this methodology is de-linked from the utility’s own and actual cost.

The capital cost is determined as the new replacement value of the efficient comparable model

and the monthly payment is calculated based on a 30 years economic life and 10% real annual

cost of capital. The operation and maintenance costs are based on effective management and

administration costs while overhead costs; on the number of customers of the company model.

There are different types of cost considered in the VAD calculation:

a) Administrative costs due to the existence of the client. This is a fixed monthly fee,

regardless of user consumption;

b) Cost for energy consumption. Each kWh consumed by the customer requires the

company distributor to purchase a kWh plus the corresponding distribution losses;

c) Cost of peak power consumption. Each KW consumed by the customer requires the

distribution company to buy that KW plus distribution losses corresponding to the

system generator;


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d) Cost per customer power demand in the local peak demand hours of the system.

This cost refers to the required capacity of facilities to cope with customer

consumption that coincides with peak demand. This requires the distribution

company to expand its substations, lines and transformers, high and low voltage to

cater for every additional KW customer demand for peaking power; and

e) Cost per customer power demand during off-peak hours. This has no impact on

investments at substations, transformers and lines away from client but nonetheless

affects the investments on facilities that that are near the clients and are more

specific to their demand behaviour.

The CNE hires one or several consulting firms to carry out the study while distribution

companies undertake the same study with consultants chosen by them, but approved by the

CNE. The results are weighted 1/3 for the study of distributor and 2/3 for the study of the CNE.

Tariffs are indexed through formulas that run for 4 years.

The VAD calculation mechanism generated the results in Figure 36 based on a reference study

conducted by the Pontifícia Universidad Católica de Chile (2009).


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Figure 36. Percentage Change in Distribution Tariffs From VAD

9.3 CHILE’S POST REFORM INSTITUTIONAL GOVERNANCE FRAMEWORK

The Ministry of Energy was recently created. It is the agency responsible for the development of

plans and policies for energy sector including forecasting the demand and domestic supply of

energy. Other institutions that have key governance roles are:

a) National Energy Commission, CNE (for its Spanish acronym). It is the entity

responsible for setting all electricity prices except those in the non-regulated retail

market. The CNE is under the Ministry of Energy.

b) Fuel and Electricity Superintendence, SEC (for its Spanish acronym). It is the entity

responsible for ensuring the correct operation of the electricity, gas and fuel

services in terms of security, quality and price. It oversees the proper

implementation of the framework laws for these industries.

c) Economic Dispatch Centers, CDEC ((for its Spanish acronym) 67 CEDCs are

independent entities that are responsible for the optimal operation of each

interconnected electrical systems, called Economic Dispatch Centers. They are also

responsible for the valuation of the energy and power transfers between generation

companies and for the calculation of the transmission lines toll to be paid by the

companies. Their Boards are made up of the representatives of generators

companies, transmission companies and non-regulated customers. By their sheer

number and by the manner of selection of representatives that is biased for the

bigger companies; generation companies particularly the big ones have a large

influence over the decisions of the Board. The inclusion of non-regulated costumers

adds transparency to the decisions and actions of the CDECs .

d) Experts Panel. The panel was an offshoot of the amendment of the Electricity Law in

2004. It consists of 2 lawyers and 5 engineers or economists who are appointed for

67

There are two CDEC in Chile, CDEC-SIC that rules the Central Interconnected System, an CDEC-SING in charge of the operation of the Big North Interconnected System.


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6 years who are selected by the members of the Chilean Court of Free Competition.

Their work is to resolve differences arising between the authority and the electricity

market agents in connection with the application of the rules set out in the

Electricity Act and its Regulations. The Expert Panel also solves the differences

between the wholesale electricity market agents who are members of CDEC.


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10 BRAZIL’S ELECTRIC POWER INDUSTRY

10.1 OVERVIEW OF THE ELECTRIC POWER INDUSTRY OF BRAZIL

Generation

The Installed generation capacity and peak load of Brazil from 2001 to 2010 is shown in Table

29. The generation system in Brazil in 2010 has an installed capacity of 112,400 MW . Total

energy generation in 2010 was 475,104 GWh ; contracted import capacity at 5,850 MW ; and,

a maximum demand at 68,307 MW.

There were 2,336 generating plants in 2010. Of these 72% (80,637 MW) of installed capacity

was hydro, 19% (21,003 MW) thermal , 7% (7,826 MW) biomass (mainly sugarcane bagasse),

2% (2,007 MW) nuclear power and 927 MW wind power. It is notable that 79% (89,390 MW) of

generating capacity is from renewable energy . An additional 18,000 MW of generating capacity

is expected to operate in 2010 to 2011.

Table 29. Installed Generating Capacity in Brazil (2001-2010)

Year Peak Load

(MW)

Installed Capacity

(MW) Reserve

2001 55,099 74,877 36%

2002 50,757 80,315 58%

2003 53,515 85,857 60%

2004 56,795 90,679 60%

2005 59,103 92,865 57%

2006 61,782 96,295 56%

2007 64,371 100,352 56%

2008 65,586 102,949 57%

2009 67,442 106,570 58%

2010 70,954 112,400 58%

The National Interconnected System (SIN) is a system of large hydrothermal base that is

predominantly hydro and with multiple ownership. The SIN consists of four major subsystems:

South, Southeast / Mid-West (the largest in the country for its application and serves the

region’s largest population and industrial production centers ), North and Northeast. All the


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hydro power systems are allowed to maintain a large energy storage capacity during the wet

years in anticipation of the dry years. The interconnections between the subsystems allow joint

optimization of the generation in different watersheds, thus leveraging on their hydrological

diversity. Current configuration allows the SIN to carry all the power generated in any of the

subsystems to the demand centers.

The system in the Amazon where energy demand is about 3% of the country is not yet fully

inter-connected to the SIN. However, the interconnection in 2001 of the capital city of Manaus

substantially reduced the number of non-interconnected systems and confined them to those

that are scattered in the Amazon region.

The system in the central Itaipu on the border with Paraguay with a demand of 14,000 MW has

a frequency conversion capability that allows Brazil to purchase power from Paraguay at 50 Hz .

There are also interconnections with Paraguay for 50 MW; with Argentina for 2050 MW; with

Venezuela for 200 MW (not integrated into the national grid in Brazil) and Uruguay for 70 MW.

Energy Import Contracts were signed with Argentina and Venezuela in addition to the

agreement to purchase power from the central Paraguay binational Itaipu dam.

Transmission

The current transmission system in Brazil has more than 95,000 km of power lines greater than

or equal to 230 kV and a transformer capacity higher than 206,000 MVA. The predominance in

the system of hydro generation located at long distances from the load centers requires a large

and complex transmission. The transmission system has voltage levels of 230, 345, 440, 500, 600

(DC) and 765 kV. The federal government maintains an important role in the sector through its

ownership of most of the basic grids.

Distribution

Brazil currently has about 70 distribution companies. A large number of major distribution

companies have private equity. However, some of the states of the federation maintain

ownership of distribution companies. System losses in Brazil range between 8% and 45% in 2008.


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The average sales price of electricity in Brazil in 2008 was approximately US$131.88/MWh. The

residential, industrial and commercial sectors registered average sales prices of US$153.49;

US$108.55 and US$147.60 per MWh, respectively. The average prices in 2010 is shown in Table

30.

Table 30. Average Price of Electricity in Brazil (2010)

Type of customer Average Tariff

(US$/MWh)

Residential 153.49

Industrial 108.55

Commercial 147.60

10.2 INDUSTRY RESTRUCTURING AND POLICY REFORM

During the 70s, all the companies in generation, transmission and distribution of electricity were

owned either by the federal or provincial governments. During the 80s and the 90s, Brazil

suffered a hyper-inflation process that, together with the freezing of the electrical tariffs

resulted to a debt of US$ 50,000 MM between the generators and distribution companies. That

debt was partially cancelled by the federal government in 1993. By then, the Brazilian state had

suffered the consequences of a severe economic crisis as a result of the high external debt. In

1995 during Fernando Cardozo’s government, it was decided to initiate reforms using other

countries such as Chile, England and Colombia as benchmarks.

The modernization of the Brazilian electric sector began in 1995 through the publication of the

Law on Public Service Awards (8.987 Act) and regulations related to the electricity market

specifically the 9.074 Act. The regulatory body was created in 1996 through the 9427 Act. In

2004 the Brazilian Government decided to make modifications in the operating model of the

sector through the enactment of Laws 10847 and 10848.

The key issues that led to the reform were:

a) High disinvestment in the electricity sector in the 1970-1990 period;


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b) Financial and technical inability by the state to provide the necessary system expansions due to the external debt crisis experienced by Brazil in the eighties;

c) Dominance of state electricity companies resulting in the need to increase the participation of the private sector;

d) Poor quality of service that showed in frequent blackouts; and

e) Low tariff levels from inefficient subsidies.

Law No. 8987 of 1995, known as the "Law on Public Service Awards” and the Sector Law No.

9047 of 19/5/1995 introduced profound and important changes, namely:

a) Opening up the industry to private investors;

b) Bidding for new generation projects;

c) Creation of the Independent Power Producer;

d) Open access to transmission and distribution systems;and,

e) Freedom for large consumers to choose their energy suppliers.

Decree No. 1717 of 1995 established the conditions and enabled the extension and

consolidation of public service concessions and approved the plans for the conclusion of the

suspended work on 22 power generation projects with a combined 10,100 MW of generating

capacity.

Decree No. 2003 of 1996 established the "Regulation of the Operation of Independent

Producers and Self-producers.”

Other laws were passed in 1997 as follows:

a) Law No. 9433, which instituted the National Water Resources Policy and created

the National Water Resources Management;

b) DNAEE (former regulator) Resolution 466, which consolidated the General

Conditions of Supply of Electricity and harmonized it with the Consumer Protection


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Code (Law No. 8078, of 1990);

c) Resolution MME (Ministry of Mines and Energy) 349, which approved the Internal

Regulation of the ANEEL established Control DNAEE management ; and

d) Decree 2410, which provided for the calculation and collection of the annual audit

of public services by all concessionaires.

Major policy reforms were made in 1998 with the publication of Provisional Measure No. 1531,

which authorized the Executive to restructure ELETROBRÁS and its subsidiaries, the most

significant of which were:

a) Authorizing the gradual withdrawal of the State from the electricity business;

b) Guaranteeing the General Reversion Reserve (RGR) until 2002 to continue the

investments in Electrobrás (Centrais Eletricas Brasileiras SA);

c) Since 2003, concessionaires or authorized may negotiate the amount of energy

with gradual reduction, the annual ratio of 25% of amounts relating to the year

2002;

d) Authorizing the separation of FURNAS into two companies: one each in generation

and transmission;

e) Authorizing the separation of ELETROSUL into two companies: one each in

generation and transmission;

f) Authorizing the separation of ELETRONORTE into five companies: two generation

companies, one transmission and one distribution in the isolated systems of Manaus

and Boa Vista, one for generation in Tucurui, and another for transmission;

g) Authorizing the separation of CHESF into three companies: two in generation and

one in transmission;

h) Authorizing ELETROBRÁS to retain stakes in the generating companies to be created


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from the separation of FURNAS, ELETROSUL, ELETRONORTE and CHESF.

In summary, the policy reforms in 1997 resulted in the following:

a) Unbundling (Generation, Transmission and Distribution);

b) Open access to transmission and distribution systems;

c) Creation of a short-term energy market and of the Mercados Atacadista de Energia (MAE) that was responsible for settlements in this market;

d) Creation of an independent Regulatory Body;

e) Re-definition of operating organisms of the system, with the participation of agents in the system;

f) Definition of traders companies and free consumers;

g) Tender for new generation projects.

The key elements of reform that were intended to incent investments in the industry by the

private sector were the :

a) Creation of a stable legal and institutional framework through laws and decrees

that permits and facilitates private sector participation in the electricity industry;

b) Privatization of distribution companies . The privatization of these non-profitable

companies provided greater security to generation investors because it allowed for

a better functioning of the long-term power markets; and

c) Adjustment of the tariffs to end-users through the removal of subsidies.

The immediate results of the reforms highlighted the importance of private participation in the

generation and distribution of electricity. From virtually zero in 1995 , private ownership rose to

3% in the generation and 32% in distribution in 1997. Between 1998 and 2000 US$ 10 Billion

was invested in the electric system by private companies. During this period, the government

successfully tendered 10,000 MW of new hydropower generating capacities. The tender for the

generation plants owned by the federal government was however stopped by the political

opposition.


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10.2.1 POLICY AND REGULATION OF GENERATION

The central regulatory policy for generation is the requirement imposed on distribution

companies and large consumers to enter into long-term contracts with generators . This policy

is mainly intended to incent investments in new generating capacities.

Distribution companies are mandated to sign contracts for 100% of their energy requirements.

Contracts must be signed for energy to be supplied by existing plants one year before they are

required; three to five years before for energy to be supplied from new plants that are still to

be built. Generators must have backup power capacity to secure their supply contracts. There

are no additional charges for generation capacity. Large consumers (Contestable Consumers)

also must contract 100% of energy requirements.

The policy reforms in 2004 created three electricity markets, namely:

a) Regulated contracting market for contracts between generation companies and

distribution companies for the demand of the regulated markets;

b) Free contracting market for bilateral contracts between generators, importers or

traders and large consumers and exporters; and

c) Energy spot market, where the Chamber of Electric Energy Commercialization (CCEE)

calculate the amounts and price differences between contracted and consumed

energy.

Regulated Contracting Market

Distribution companies must secure their energy requirements through contracts in the

Regulated Contracting Market (ACR). ANEEL is responsible for the regulation, organization and

conduct of the bidding process directly or through the Chamber of Electric Energy

Commercialization (CCEE).


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The winning companies at the auction are those that offer the lowest price per MWh to supply

the distribution companies. Regulated Market Contracts are signed between the winning

generators and distribution companies.

The main design elements of the auction are:

a) Total energy purchases must be made through auction based on the lowest price

method;

b) Procurement is carried out jointly by distributors through the pooling of their energy

requirements in order to obtain economies of scale in contracts associated with

new generation projects in addition to spreading the risks;

c) Auctions are held separately for new power plants (supply to the expansion of

demand) and for existing plants, both by tender.

There are three types of auctions. Given that “A” represents the starting year for energy supply,

the auctions that are held are:

a) Auctions (A - 5) performed in the fifth year preceding the year A;

b) Auctions (A - 3) made in the third year preceding the year A;

c) Auctions (A - 1) made in the year preceding the year to start of supply.

Auctions (A-5) and (A-3) are made for the purchase of power from new generation projects and

(A-1) for the purchase of energy from existing plants. Additionally ANEEL may conduct

Adjustment auctions in order to supplement the supply for distribution companies to at most

1% of their demand. Finally, there are auctions for energy from renewable sources and for

backup energy. Sellers in this market must have physical support for their contracted energies

from their own plants or through contracts with other generators or electricity traders.

Every year until the first of August the distribution companies, energy traders , and large

consumers must submit their forecast demand for the next five years to the Ministry of Mines

and Energy . The Ministry determines the sum of the demands of distribution companies and


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that are to be auctioned (A-5) in the regulated contracting market. The energy needs of other

agents are met in the free contracting market.

Distribution companies can change their forecast for the year A, three years before the supply

will be required. The limit of this change is 2% of the load. The Ministry determines the total

amount of these requirements and may hold an auction (A-3).

Distribution companies can make a new forecast a year before the year A, limited to 5% of its

market for the replacement of contracts that are about to expire. The Ministry determines the

amount of the new demand and may hold an auction A-1. The amount of energy that the

distribution companies can buy from this auction is limited 1% of their total contracted load.

The duration of contracts with new power plants (auctions (A-5) and (A-3)) is at least 15 years

and a maximum of 30 years counted from the start of supply. For contracts with existing plants

(auctions (A-1)) the duration is at least 5 years and a maximum of 15 years. For supplies from

other sources; the contract duration is between 10 and 30 years .

In addition to the regular auctions , Setting auctions may be held for energy requirements within

four months after the auction with supply period of up to two years. These are for energy

requirements that were not forecasted or caused by unexpected situations that could not be

included in the A-5 and A-3 auctions. Setting auctions cannot involve more than 1% of the

energy tendered in the regular auctions and are held in the same year as the A-5 and A-3

auctions.

Generation projects identified by the Energy Research Company (EPE) and approved by

resolution of the National Energy Policy Council (CNPE) are considered priorities for their

strategic and public interest and are included in the auction (A-5) and (A-3).

To increase the security of supply, reserve power auctions are held to sell backup power from

generation centrals hired by the Chamber of Electric Energy Commercialization (CCEE) for this

purpose.


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Generation companies can contract for either energy or availability. Energy is a classical contract

in which the generator assumes the risks of not being able to supply the energy (when this

happens, the generator will have to assume the costs of buying the energy in the spot market).

In such energy contracts, the generator assumes also the risk associated with increasing fuel

prices. As for the availability contract, there is a minimum availability to be met by the generator

and in the case of non-performance, there are penalties to be paid by the generator. However,

the distributor assumes the costs of buying in the spot market or the risk associated with the

prices of fuel. In energy contracts, generation companies assume the risk of generating energy

in the contracted amount. In availability contracts, the risk in the amount of energy generated

belongs to the distribution companies that sign the contract. The Ministry is opting for

availability contracts for thermic central where distribution companies assume the payment of

fuel.

Free Contracting Environment

Consumers with demand exceeding 3 MW that were connected after July 1995 and the

consumers with supply voltage exceeding 69 kV and connected prior to this date can buy their

energy from any supplier.

Consumers with demand exceeding 500 kW can buy power from the local distribution

concessionaire at regulated rates . Alternatively, they are free to enter into power purchase

contracts with small generators particularly small hydropower, biomass thermal or wind.

Law 10.848 of 2004 created the Free Contracting Market. In this market, customers conclude

bilateral contracts freely with generators, traders and importers. Free Customers should be free

agents of CCEE. They can be represented for the purposes of accounting and settlement by

other agents of that chamber that means that some agents can act in the name of others

(through a power of attorney). This is due to the fact that some free agents do not have enough

technical knowledge or economical resources to manage their contracts so they could associate

and/or be represented by third parties. It is estimated that 25% of the country's current demand

are from free customers.


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A consumer in the free contracting market who wishes to revert to the distribution company in

his/her area for the supply electricity must advise of its intention to do so 5 years in advance.

Energy Spot Market

The short term energy market in Brazil can be defined as a generators’ pool. The transactions

and prices not covered by the long term contracts are resolved in this pool. The participants in

the spot markets are generators, distributors, traders and free customers.

The Differences Settlement Price (PLD), is used to value energy transactions in the short-term

markets and is the difference between contracted amounts and quantities currently generated

and consumed. The PLD is derived by the national system operator ONS (Operador Nacional do

Sistema Electrico) with the use of power system operation optimization models. There are two

models, the NEWAVE model with five years horizon and monthly simulations and DECOMP

model with 12 months horizon. The models find the optimal solution using the reservoirs, taking

into account the benefit of present water use and the expected future benefit of storing water,

reducing fuel costs and future failure.

The PLD is determined weekly for each of the three load steps and for each submarket (North,

Northeast, Southeast / Mid-West and South). It is equal to the marginal cost, but must be within

floor and ceiling prices that in 2010 were at US$ 7.2 MWh and US$ 350 MW Respectively.

When the level of hydropower reservoirs in each region is below the safety limit, the ONS

activates the Risk Aversion curve and prioritizes the entry of thermal and other energy imports

even if the marginal cost of hydro generation obtained from the models is less than the cost of

these resources. In this case the PLD is equal to the "cost risk", i.e. the price of more expensive

energy resources dispatched.

The calculation of the PLD has no transmission constraints within each submarket. As such,

energy is assumed to be equally available in all points of the sub-market and the price is unique


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within each submarket. In contrast, the PLD calculation takes into account transmission

constraints between the various submarkets.

The calculation of the PLD is based on ex-ante dispatch ,i.e.; prior to the real operation of the

system.

The settlement of the income of hydropower in the spot market is done through the Energy

Reallocation Mechanism (MRE). The MRE is based on the concept of Assured Energy of

hydroelectric plants. The Assured Energy of each hydropower plant is determined by ANEEL by a

method of energy allocation to be supplied by the set of hydro plants with a defined probability

of occurrence. The MRE assures that all hydro plants receive a minimum income whose

calculation depends on its Assured Energy regardless of actual energy production. In other

words, hydro plants act as an energy pool to compensate those plants that produce under their

assured energy.

If there is secondary energy source in the system, the energy generated over the total

committed energy is allocated between the hydro generators in the proportion of their

committed energy.

10.2.2 POLICY AND REGULATION OF TRANSMISSION

Transmission concessionaires are responsible for the maintenance and availability of their

facilities. The facilities are operated by the ONS. There is open access to the transmission lines

subject to the payment of transmission charges and compliance with operational and

contracting procedures.

Transmission system planning is performed centrally by the Energy Research Company (EPE).

The main studies are contained in the Ten-Year Energy Plan (PDE) and cover a 10 year horizon

for the generation and transmission systems and a 5 year horizon for the Transmission

Expansion Program (PET) .

Transmission facilities are classified as:


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a) Basic Grid (trunk grid): voltage installations greater than or equal to 230 kV;

b) Border: transformer facilities with voltage greater than or equal to 230 kV that

feeding network with lower voltage distribution at 230 kV; and

c) Other transmission facilities (DIT) at any level of voltage for the exclusive use or

shared use of generators or exclusive use of free-choice consumers.

The new facilities needed for the expansion of the Basic grid are tendered through an auction

while the reinforcements in the existing concessions are approved by ANEEL.

Transmission concession contracts are generally signed for thirty-year periods. Contracts define

the pay revisions every four years and annual rate adjustments according to the IPCA index

(Indice General de Precios al Mayor –General Index for Wholesale prices).

For the purposes of remuneration, the Backbone facilities are divided into: (a) Current Facilities;

(b) New Facilities Authorized; and (c) New Facilities Tendered.

The remuneration for current facilities consists of the depreciation expense allowance and

return on assets that are based on the regulated rate of return. The revenue associated with

these facilities for most companies were defined in 1999 and is subject to adjustments

according to the IGP-M index until 2015 at the expiration of their concession contracts.

New transmission facilities are authorized by specific resolution of ANEEL. Their payment

includes an allowance for depreciation and return on investments on new and replacement

facilities as recommended by the EPE or the ONS to increase transmission capacity or system

reliability. The annual remuneration is calculated as an authorized investment annuity in the

form of a regulated rate of return that is reviewed every four years.

The construction and maintenance of new assets for existing transmission systems is awarded

through an auction. The annual income allowed (RAP) to the transmission agent is based on its


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bid and is paid for a period of 30 years with adjustments as provided in the concession contract.

ANEEL determines the maximum values for the acceptable RAP in the tenders.

ANEEL employs the Capital Asset Pricing Model (CAPM) to calculate the return on equity

component of the regulated rate of return. Allowable leverage is 63.55% for both existing

companies and for new entrants. The real rate of return in domestic currency after tax that was

adopted in the second tariff review cycle (2009-2013) was 7.24% for companies existing in 1999,

and for projects tendered for construction since 2000. The regulated rate of return is updated

every five years (the fifth, tenth and fifteenth year) . It was adjusted in 2010 to 6.00% in real

terms and after tax.

Payments are based on the efficient cost of an efficient transmission company that is derived by

ANEEL taking into account the actual conditions in the geographic area of the concession. The

costs covered in the payments include the operation and maintenance of electrical networks,

commercial management, direction and management. The methodology for the second periodic

review of cost was approved by the Normative Resolution 386 of December 15, 2009, where

operational costs were determined based on benchmarking methods.

The transmission usage fees or tariffs (TUST) are set by ANEEL. The fee structure provides

locational signals and imposes higher charges on those using the system in greater proportion.

TUST had two components starting in July 2004. These are:

a) The TUSTRB, for facilities of the basic grid with voltage less than 230 kV, which is

calculated by the Investment Cost Relating Pricing (ICRP) nodal methodology, and;

b) The TUSTFR, for the transformer facilities with voltage greater than or equal to 230

kV, and feeding distribution networks with voltage less than 230 kV, and for other

DIT’s transmission facilities that are shared by distribution concessionaires.

The TUST is calculated from the Nodal Program simulation and computational system. Rates are

based on the use of the grid and demand at each node depending on the intensity of use for the


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injections or withdrawals of power. Charges are based on the long-run marginal costs (LRMC) to

inject to or extract 1 MW from the grid. The methodology considers the minimal total

investment cost of an ideal grid and assumes that network expansion and re-routing of

transmission lines are performed continuously. As the amount of remunerations calculated by

the nodal method does not allow the full recovery of network investments, a constant

adjustment factor, R $ (reais) per MW is added to the rates.

Small hydropower (PCHs) and generation projects that use alternative energy sources (such

solar, biomass, wind and CHP) with power less than or equal to 30 MW have the right to a

discount of at least 50% on transmission and distribution tariffs for the energy commercialized.

The exact percentage is determined in their authorizations.

Resolution No. 267, a legislation that was passed in June 2007, changed the calculation of the

TUST for new companies that participate in the generation auctions. For energy auctions ANEEL

publishes a set of TUST for the new installations with direct connection to the basic network not

being in commercial operation.

10.2.3 POLICY AND REGULATION OF DISTRIBUTION

Distribution concessionaires cannot participate or own shares directly or indirectly or perform

activities in generation and transmission in the same way that generation concessionaires

cannot be controlled by distribution concessionaires. Distributors can sell energy to free

consumers except for those located in its franchise area where rates and terms applied to

regulated captive customers are used. These restrictions do not apply to distribution companies

in isolated systems, or in their own market for market smaller than 500 GWh per year.

Distributors are allowed to charge their customers for energy costs that are up to 3% higher

than the contract price in the energy auction. Subcontracting for energy supply is not allowed .

A distributor that is in deficit must buy power in the short term market subject to the payment

of penalties.


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Distribution tariffs reflect the prudent cost of investments required to deliver the service and to

comply with the requirements of the concession contract such as on service quality. Eligible

assets determined for a reference network are initially valued at their replacement cost

according to a price database maintained by ANEEL and are thereafter adjusted based on a

productivity index. The prices in the ANEEL database are the average prices in the last four years

by type of equipment on actual purchases made by the concessionaire. The replacement value

of assets is then multiplied by a factor called “exploitation index”. The index reflects the degree

to which assets are currently employed and removes the value of not used or not useful assets,

e.g. those oversized from the valuation of the rate base.

Operating costs, maintenance, administration and commercial management are de-linked from

actual costs incurred and are instead calculated by ANEEL by the Reference Network

methodology. An optimal capital structure that was derived from empirical data from

comparable electricity distribution companies in Brazil, Argentina, Chile, Australia and Britain is

used in the WACC . This structure allows for 57.16% of debt . The rate of return in real terms is

9.95% after tax.

The pricing methodology is a Wholesale Price Index (WPI) – X price cap. Concessions that were

signed with power distributors from 1995 provided for initial rates and adjustment mechanisms

in the periodic rate revisions, extraordinary rate revisions and annual rate re-adjustment. Rate

Review occurs every four years.

10.2.4 POLICY AND REGULATION FOR RENEWABLE ENERGY

Generating capacity from renewable energy increased by 5,200 MW in the period 2004-2009.

These were mainly from two resources: bioelectricity cogeneration from sugarcane bagasse, and

small hydro from plants with capacities of less than 30 MW. These plants have been

participating in the energy auctions carried out by distribution companies to supply their loads;

competing with traditional generation companies. In the last two years, 800 MW of wind power

were in operation and under construction. An additional 1,800 MW of new capacity was

contracted in the 2009 auction.


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The biggest obstacle to the construction of these plants has been the inability of the existing

regional grids to accommodate new power injections. It thus became necessary to plan grid

reinforcements. To this end, a new regulatory design known as the IGC Scheme was agreed

between ANEEL and the RE investors. The agreement calls for:

a) Generators to hire a technical team to plan the integration network in cooperation

with EPE. The planning of the integration network would be carried out on a least-

cost basis through the use of an optimization model to optimally locate the IGC

facilities and minimize investment costs. The proposed plan would be subject to

ANEEL´s approval;

b) Generators to pay for 100% of the IGC costs plus the basic grid tariff (TUST); and

c) Distribution companies to (exceptionally) waive their right to build the IGC assets

and an auction will be held for the right to operate and maintain the IGC facilities.

As agreed in the IGC scheme, generators will pay for all integration network construction and

maintenance costs. Because the network had a tree structure, it was easy to calculate the

fraction of each generator’s injection that would flow across each circuit. This allowed the

application of a MW-mile scheme where each generator pays for the cost of each circuit in

proportion to its use.

ANEEL held an auction in 2010 to grant the concession of the ICG facilities that will be used to

integrate about 1,800 MW of Wind Power in the northeastern and southern regions of Brazil.

10.3 BRAZIL’S POST REFORM INSTITUTIONAL GOVERNANCE FRAMEWORK

The governance framework set up by the reform comprised of three institutions: the system

operator (ONS), the regulator (ANEEL) and a body responsible for the settlement of short-term

market called “Mercado Atacadista de Energía” (MAE). They are guided and assisted by other

agencies that are involved with the electric power industry.


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MAE is supervised by the Ministry of Energy and Mines. It is however a non-profit private

institution,. The President of its Governing Council is designated by the Ministry. The President

also has veto power.

The formulation , implementation and monitoring of the electricity sector policies are the

responsibilities of the Ministry of Mines and Energy (MME) under the guidelines of the National

Energy Policy Council (CNPE). CNPE is chaired by the Mines and Energy Minister. Its principal

duty is to recommend to the Brazilian President energy policy, the bidding of special projects

in the electricity sector and the definition of safety criteria for electricity supply. Within the

Ministry's structure is the electrical energy secretary whose key responsibilities include to

coordinate ; provide guidance and control the Ministry´s actions with respect to the politics of

power sector; security of supply under the established quality standards; continuity and safety;

and, the definition of fair rates for consumers and one which encourages medium and long

term investments.

Electric Energy National Agency (ANEEL) is the regulatory body. It is responsible for developing

regulations and legislation; for the auction of generation and transmission projects and for the

power supply of distribution companies.

The Energy Research Company (EPE) is a state-owned enterprise in charge of research and

studies of the energy sector planning. The company draws up every year the electrical system

expansion plan for the next 5 years.

The National Electric System Operator (ONS) is responsible for coordinating and controlling the

operation of the national grid; implementing an optimization of energy resources; ensuring

security of supply and service quality standards taking into account the conditions imposed for

multipurpose water reservoirs and the limitations of the generation and transmission systems .

The Chamber of Electric Energy Commercialization (CCEE) is an association of electricity market

players and institutions. Its main function is to register and manage the electricity supply


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contracts signed between generation companies, trading companies, distribution companies

and large users. The most important activity carried out by the CCEE is the calculation and

payment of the spot market prices.

The Monitoring Committee Electricity Sector (CMSE) is an institution whose function is to

analyze the continuity and quality of power supply in a five years period, and develop preventive

measures and actions on the demand side and generation system.


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11 KEY POINTS AND LESSONS LEARNED FROM INTERNATIONAL

EXPERIENCE

The policy and regulatory reforms in Chile and Brazil had many aspects in common. Among the

most important are:

a) Vertical Disintegration of activities where competition between players could be

possible (i.e. power generation and commercialization) and the regulated activities

(i.e. distribution and transmission);

b) Both countries actively fostered competition in generation and commercialization

activities in order to reduce electricity prices to the consumers;

c) Requirement for distribution utilities and large users to sign bilateral contracts for

100% of their forecast demand through auctions in order to incent generation

investments;

d) The creation of wholesale spot market that is primarily a balancing market for

generators and distributors (plus traders and free customers in Brazil) for their

contractual commitments. In these markets the dispatch is based on the variable

operating costs of thermoelectric generation units and on the water’s opportunity

cost for dammed hydro generation plants;

e) Decentralization of the investment decisions for the expansion of the transmission

grids and new generation capacity;

f) Tariffs related to the usage of transmission and distribution grids are benchmarked

to the cost of an efficient utility, the reference network, and de-linked from the

utilities own cost;

g) Open access to transmission and distribution networks is guaranteed by law, once

the security and reliability conditions are met. Access tariffs are regulated; and


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h) Strong and comprehensive institutional governance framework that clearly allocates

responsibilities for policy, planning, regulation and dispute resolution among

government and non-government organizations.

However there are also differences between the two reform processes, the following being the

most notable:

a) In the Chilean case, power sector privatization was directed at Chilean investments,

however during the 90’s some companies were bought by international companies.

In Brazil national and international companies participated in the privatizations;

b) In Brazil, the regulator conducts three types of bids for distribution companies

depending on when the supply is needed. In Chile, distribution companies set their

own bidding terms but each bid must be approved by the regulator;

c) Brazil permits big end users to participate as agents in the electricity market. They

can buy in the wholesale market their requirement for the short and long term. In

Chile, end users have no access to the wholesale energy market. They have to buy

energy and power from a generation or distribution company; and

d) Brazilian methodology for the calculation of the regulated transmission tariff is

based on the long term marginal cost. In Chile the tariff calculation is based in the

short term marginal cost and the market agent’s use of the grid.

The following highlights the weaknesses of the Chilean regulation reforms:

a) In the beginning Transmission and Generation were not separated. This caused

innumerable problems and a great barrier to the entry of new players in the

electricity market. This weakness was overcome some year later by the Chilean

antimonopoly organism who decreed that both activities shall be separated;

b) The huge participation of the principal generation company of the system, ENDESA

plus the problem that most of the water usage rights are owned by this company.


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This problem has not been solved; the only partial solution has been a tax for the

unused water rights;

c) Vertical integration between the principal generation company and the biggest

distribution company. This problem still persists but its adverse effects have been

softened by the open bids for the distribution companies’ supply;

d) Absence of a regulatory mechanism for the quick resolution of disputes leading to

proceedings/litigation of issues that could not be addressed properly by

authorities and to the extent that the authority could not act in properly during

the supply crisis. This problem was superseded with the creation of the “Experts

Panel” that solves the conflicts between market agents;

e) State entities in charge of the definition and implementation of energy policies, and

the regulation and supervision of the electricity sector activities were weak. These

problems were gradually addressed by initially, giving more authority to the

superintendent’s office and later, by the creation of the Ministry of Energy;

f) Privatization did not promote investment in power generation as has been proven in

Chile. The growth in generation capacity was not sufficient to fulfill demand growth

and the supply security needed. This lack of investment is in part explained by the

dominant position of the biggest generation company, which is primarily

hydroelectric and owns most of the generation water rights, who has extra profits

with the delay of generation project; and

g) Usually the investments in generation respond to energy prices and supply crisis.

The bids for distribution companies’ supply and new mining projects have worked as

incentive for new power generation.


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12 COMPARATIVE MARKET ANALYSIS: CHILE, BRAZIL AND PHILIPPINES

The power markets of Chile, Brazil and the Philippines are compared in Table 31 below.

Table 31. Comparative Analysis of Chile, Brazil and Philppine Power Markets

Market Feature Chile Brazil Philippines

Promulgation of Reforms

Main reform in 1982. In 2005 the distribution bids were imposed

1995 and 2001 2001

Policy and Planning

Ministry of Energy Fuel and Electricity Superintendence

National Energy Policy Council (CNPE); Ministry of Mines and Energy; Energy Research Company; Monitoring Committee for the Electricity Sector

JCPC Department of Energy

Regulator Comisión Nacional de Energía , CNE

Electric Energy National Agency (ANEEL)

Energy Regulatory Commission (ERC)

Dispute Resolution

Independent Experts Panel

Appointment of Dispute Resolution Administrator and Panel Group; disputes can be raised in court

ERC subject to recourse to the court Sectoral Dispute Resolution Mechanisms in WESM, GMC, DMC

Designation Process of Regulator

Selected by Senior Public Management System and approved by the President

Proposed by the President and approved by Senate

Appointed by the President

Regulated Activities

Transmission, distribution. Generation through auctions

Transmission, distribution. Generation through auctions

Transmission & Distribution Generation until retail competition and open access declared

Types of Power Markets

Bilateral contracts through auctions(distributors and free users100% contracted); Centralized SPOT Market (short-term marginal cost based dispatch pool, “SMP”)

Bilateral contracts through auctions (distributors 100% contracted; Capacity contract optimization model and Spot market based on long run marginal cost (“LRMC”)

Negotiated bilateral contracts; Centralized SPOT Market (bid price-based dispatch gross pool)

System Operator

Economical Load Dispatching Center (Centro de Despacho Económico de Cargas, CDEC)

National Operator of the Electrical Systema (Operador Nacional do Sistema Eléctrico, O N S.)

National Grid Corporation of the Philippines (NGCP)


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Market Operator

Private. Centro de Despacho Económico de Cargas, CDEC (membership from generation, distribution and free users)

Private. Chamber of Electric Energy Commercialization (CCEE)

Philippine Electricity Market Corporation (PEMC) pending selection of IMO.

Peak Demand SIC: 6200 MW SING: 1900 MW

70, 954 MW 9,472 in 2009 (Country) 7,643 MW (Luzon Grid - 2010)

Major Players in Generation (by % of total demand)

SIC: ENDESA COLBUN AES GENER

SING: E-CL(SUEZ AES GENER: GAS ATACAMA: Others

ELECTROBRAS, the state company is the major generator and distributor

Luzon: SMC Group Lopez Group Aboitiz Group NPC/PSALM

Visayas: NPC/PSALM Global Business Power Lopez Group

Mindanao: NPC/PSALM Aboitiz Group CEPALCO

Existence of Supply Sector

generators and distributors

Generators , distributors, traders

Distributors; and with retail competition, generators, retail electricity suppliers

Free clients or Contestable Market

Those with demand of at least 2 MW . No provision for retail competition at household level

Demand >3 MW. No provision for competition at household level

Open Access and Retail Competition is yet to be implemented. Thresholds are 1

st, consumers with

demand of 1 MW and above; 2

nd, 750 kW and

above 2 years after with possible aggregation; 3

rd,

all consumers 7 yrs after 2

nd stage.

Type of Pool

Balancing Market. Generators only

Net Pool. Generators, distributors, traders and free customers for energy requirements not covered by long-term contracts

Gross pool


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Method of Settlement in Spot Market

Direct settlement between generators based on SMP and net balance calculated by CDECs. SMP based on variable cost of most expensive generator dispatched. Thermoelectric generators required to submit operating costs that could be audited by CDECs.

Differences Settlement Price (LPD) determined by ONS. PLD subject to floor and ceiling: US$ 7.2 /MWH and US 350 MW in 2010 respectively

Net settlement at nodal prices using the differencing model

68 .

Generators bid Prices for each hour.

Dispatch Centralized at the lowest cost, independently of the contracts

Economic dispatch submit to optimization model

Central scheduling and dispatch using optimization model, independently of the contracts

Capacity charge

Capacity is remunerated only in peak hours (note that auction price is node price + 20% and bid awarded to lowest energy price)

Lowest capacity charge in the auction

No Capacity Remuneration in WESM; capacity charge included in negotiated bilateral contracts

Degree of Privatization (in Generation)

100% 10% 85% of the total capacity of generating assets in Luzon and Visayas

Existence of Subsidies

None Residential customers Missionary customers from universal charge; lifeline customers (with consumption of 100 kWh and below) as well as senior citizens are subsidized by non-lifeline and non-senior citizen customers

Presence of Dominant Power Player

ENDESA controls more tan 40% of SIC generation E-CL controls about 50% of the generation of SING

ELECTROBRAS , the state company is the dominant player in generarion and distribution

MERALCO (the largest DU controls nearly 70% of the Luzon grid)

Market Share of DUs (based on demand)

75% del SIC 10% del SING

70% 99% Luzon; 96% Visayas; 85% Mindanao

68

For a settlement system that works on a differencing basis, each exit point from the transmission network is assigned to a standard retailer, and that retailer has the prima facie responsibility for payment for all energy that passes through that exit point. That energy is purchased at the appropriate reference node pool price multiplied by the loss factor appropriate to the exit point.


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Number of Customers in the market

More than 4 million More than 40 million More than 5 million

Generation Barriers

For hydro the main barrier is the control of water usage rights by the largest generation company (ENDESA). For Thermoelectrics the main barrier are environmental approvals, people opposition and availability of assured Natural Gas. For small projects the main barrier is the lack of transmission infrastructure.

Environmental licensing process still complex; availability of acquisition of natural gas

Complex and multifarious authorization and permitting requirements including health, safety and environmental clearance is still required from government agencies. Highly concentrated Distribution Market with a single DU accounting for ~70% of the main grid.

Participation of Generators in the Market

Without restriction Without restriction No Single company, related group or IPP Administrator allowed to own, operate or control more than 30% of installed generating capacity in a grid and/or 25% of installed generating capacity

Driver of Growth in Generation

Contracts with distribution companies (Public bidding process) and non-regulated customers.

Auctions in the regulated and in the free market

None

Transmission Expansions

New works are open and competitive to any operator. Expansion of existing works are compulsory for the owner

Expansion of the system through auctions

Expansion planned & carried out by the National Grid Corporation of the Philippines (NGCP)

Regulatory reform and restructuring in the three countries were motivated by a common need

to create an efficient electric power industry. Their broad policy and market architectures and

institutional governance frameworks are similar: liberalization of generation; regulation of

network services; creation of wholesale and retail markets; and the creation of separate policy

and regulatory institutions. They also face the same challenge from dominant utilities. However,

the detailed policy, regulatory and institutional market designs markedly varies between Chile


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and Brazil on the one hand; and the Philippines in the other. These differences may well explain

the performance of the markets in the three countries, specifically, on generation investments.

Chile and Brazil have achieved generation adequacy; the Philippines has not and is instead facing

supply shortages particularly in the Luzon and Mindanao grids. Market size and privatization do

not appear to explain these differences. The power markets of Chile and the Philippines are

comparable in size and both countries have actively pursued privatization. Brazil on the other

hand has a large market and the government continues to hold ownership interests in most of

the country’s distribution utilities and generating plants. While these disparate achievements

could be partly because the two comparator countries, particularly Chile implemented drastic

reforms much earlier than the Philippines that gave them a lead time to assess the effectiveness

and re-calibrate their policies; it also signals the need for an in-depth examination and

adjustments of the policy and institutional design in the latter.

The distinguishing feature of Chile’s and Brazil’s markets is the sequencing of policy reforms that

prioritize the achievement of generation adequacy over wholesale and retail competition.

Distributors and large users are required to contract for 100% of their forecasted demand and

sign long-term contracts from the public auctions that are managed by the regulator. The

regulator sets the price caps and approves the terms (actually draws up the bidding terms in

Brazil) of the auction. The system has greatly reduced market risk and the risk of regulatory

opportunism which provides a strong incentive for generation investments. Since generators

and other suppliers must compete to supply under strict bidding terms including a price cap that

is set before the auction ; consumers benefit from the efficiency of competition, albeit, from

competition for the market, rather than competition in the market. The exercise of market

power by dominant generators and/or distributors is curtailed because both are required to

contract by auction.

As a result of the 100% bilateral contract requirement, the wholesale spot market in Chile is a

balancing market for generators only while that in Brazil is a net pool for energy requirements of

distributors, generators , traders, and large users that are not covered by these long-term

contracts. At the same time, both Brazil and Chile have placed higher thresholds than the

Philippines for initial retail market contestability at over 3 MW and 2 MW respectively and have


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not mandated contestability at the household levels. In contrast, bilateral contracts in the

Philippines are bilaterally negotiated and are predominantly for 1-3 years only. Distributors and

eventually, contestable market customers will be allowed to secure their energy supplies from

the spot market subject only to the distributor’s compliance with their economic sourcing

obligation under the law.

Construction of new transmission facilities in Chile and Brazil are awarded by auction for which

tariffs, like those of distribution, are benchmarked to the cost of an efficient utility or the

“reference network”. Again in contrast, the Philippine PBR methodology for setting

transmission and distribution tariffs does not de-link tariffs from the utilities’ own cost.

The institutional governance structures in Chile and Brazil are characterized by the clear

delineation of oversight, policy, planning and regulatory responsibilities among separate

agencies that coordinate closely to ensure the efficient operation of the industry. They also

include dispute resolution mechanisms separate from the regulator to facilitate prompt conflict

resolution between the regulator and market agents and among market agents. Expert and

arbitration panels whose members are drawn from the private sector provide a ready

mechanism for the prompt resolution of disputes.

Institutional governance of the Philippine electric power industry to date has been marked by

the virtual withdrawal of the DOE from the scene and the regulator’s insistence on its

independence to the extent of making coordination difficult with other agencies. The JCPC is

perceived by industry stakeholders to be largely passive. The laws creating WESM, the Grid

Management Committee (GMC) and Distribution Management Committee (DMC) all provide for

the creation of Dispute Resolution Mechanisms . Apart from catering only to their respective

concerns; those of the GMC and DMC have yet to be activated. A dispute resolution mechanism

that will mediate all types of conflicts between the regulator and market agents and among all

market agents outside the concerns in WESM and the technical concerns covered by the GMC

and DMC have not been created.


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IV PROPOSED REFORMS FOR PHILIPPINE POWER

INDUSTRY


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13 POLICY AND REGULATORY REFORMS

The preceding analysis of the industry’s policy framework and international markets points to a

need for a number of policy and regulatory forms, many of which are urgent. These reforms are

categorized into those that needs to be implemented immediately and in the medium term (1 to

3 years) on the strength of their potential to incent new generation investments and are listed

by their order of importance. Except for the amendment of the horizontal policy and the scope

of NEA’s guarantee provision that require legislative enactment, the foregoing requires no more

than executive/regulatory actions to implement.

13.1 IMMEDIATE REFORMS

13.1.1 COMPETITIVE BIDDING OF FORWARD POWER CONTRACTS

All distribution utilities (PDUs, ECs) should contract for 100% of their energy and capacity

requirements through a public bidding. Therefore the utilities (with the prior endorsement of

the ERC and DOE) shall hold yearly public auctions for contracts with a maximum term of 15

years. Purchases from the spot market shall be limited to 5% of the DUs’ and generators’

contractual imbalances and shall be subject to the payment of penalties to be determined by

the ERC. Standard contract templates to be drawn up by ERC and DOE, generators and DUs .

Contract quantities shall have priority over spot ones in case of planned brownouts due to

supply shortages (no supply guaranty for uncontracted energy in case of rationing). A sample

contract from the Brazil auction is attached .

13.1.2 DEFERMENT OF RETAIL COMPETITION

Retail competition must be deferred until such time that the vital requirements laid down in ERC

Resolution No. 03, Series of 2007 is achieved:

c) Adequacy of generation, transmission networks , and customer switching systems; and


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d) Promulgation by the ERC of all pertinent rules and regulations governing retail

competition and open access. ERC shall determine the timetable with duties and

responsible parties in charge of executing the pending requirements to materialize

RC&OA. Certainty shall be given to the industry in order to allow proper planning.

13.1.3 RESTRUCTURING OF THE OWNERSHIP OF ELECTRIC COOPERATIVES

ECs may be restructured and consolidated to a small group of equity investors to strengthen the

incentives for productive efficiency. In the interim, the energy requirements of the ECs should

be aggregated by grid and tendered in the auction as one. Section 30 of the EPIRA shall be

amended by Congress to allow NEA to act as guarantor for the bilateral contract obligations of

the ECs, instead of their WESM purchases.

13.1.4 LIMITING ERC‟S ADJUSTMENT TO INSTALLED GENERATING CAPACITY

Adjustment to generating capacity must be limited to permanent derating to avoid the possible

circumvention of the grid limits from the declaration of temporary reductions in capacity.

13.2 MEDIUM TERM REFORMS

13.2.1 PROPER IMPLEMENTATION OF THE PBR RATE-SETTING METHODOLOGY

Proper implementation of the PBR rate-setting methodology for transmission and private

distribution utilities and of the RSEC-WR and proposed PBR for Electric Cooperatives to improve

the utilities’ efficiency and moderate the increases in electricity rates.

13.2.2 AMENDMENT OF THE HORIZONTAL SEPARATION POLICY ON GENERATION

Legislative Amendment of the horizontal separation policy on generation such that the grid limit

is based solely on control of the installed generating capacity. In this regard, installed generating

capacity shall cover IPP capacities whose control were ceded by the NPC/PSALM to the

administrators in the IPPA Agreements.


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13.2.3 INTERCONNECTION OF LUZON, VISAYAS AND MINDANAO

The Luzon, Visayas and Mindanao grids must be interconnected to mitigate the adverse effect

on energy security of each grid’s high reliance on a single fuel/energy resource.

13.2.4 STRENGTHENING OF THE WESM

The wholesale spot market must be strengthened to incent new generation investments by:

e) Reviewing the system operation and network reliability protocols to make them consistent with consumer valuation;

f) Demand metering to allow consumers to react to changes in the supply and demand balance;

g) Raising the price cap and sticking to it;

h) Creation of operating reserve, financial hedging, capacity markets and market for transmission rights to mitigate market risks and solve the ‘missing money’ problem.

13.2.5 VERTICAL SEPARATION OF GENERATION AND DISTRIBUTION SECTORS

The generation and distribution sectors must be vertically separated (i.e., remove cross-

ownership) to create robust competition in generation.


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14 INSTITUTIONAL GOVERNANCE REFORMS

The weakness of the institutional governance framework has its roots on: (1) the institutional

paralysis of the DOE; (2) weak administrative capacity of the ERC; and (3) a litigious regulatory

process that does not welcome broad participation and consultations and precludes an effective

appeal mechanism to redress grievances.

14.1 DOE’S ASSERTION OF ITS AUTHORITY UNDER EPIRA

The institutional paralysis of the DOE is self-inflicted and stems from its misreading of, rather

than an actual downgrading of its role under the law. There are anecdotal evidences to support

the view that the mass exodus of its staff after the EPIRA was caused more by frustration over

the perceived diminution of its role rather than from low salaries. The DOE must step up into

the plate; assert is authority and deliver on its responsibilities under the law.

14.2 STRENGTHENING OF ADMINISTRATIVE CAPACITY OF ERC THROUGH FINANCIAL

AUTONOMY AND MAINTAINING A BALANCE OF EXPERTISE

Strengthening the administrative capacity of ERC will require first, financial autonomy either

through an automatic appropriation of its budget or by allowing the agency to keep and spend

its collections instead of these being remitted to the National Treasury; and second,

maintaining a balance of expertise in the Commission, i.e., finance rather than accounting

(financial policy and strategy is more critical than accounting ); power engineers (not just any

engineer); regulatory economists (or in their absence, micro rather than macro economists); and

lawyers. The present composition of the Commission and its top executive management which

is dominated by lawyers should be restructured to achieve a more balanced composition of

these disciplines. Regulation of infrastructure industries such as the electric power industry is

more about economics rather than law and involves the consideration of the economic, financial,

and technical impact of regulatory decisions rather than on the establishment and conformity

with legal precedents that may be irrelevant to the case on hand. The current set-up where the

Commissioners are appointed by the President need not be changed. However, the names and


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Malacanang , DOE and ERC websites so that a public vetting process takes place before their

appointment by the President.

14.3 FLEXIBILITY IN THE REGULATORY PROCESSES

Short of abrogating the quasi-judicial character of the ERC (that will require legislative

amendment); what is required is flexibility in the regulator’s processes that will: (1) invite broad

debate of and meaningful participation by all stakeholders; (2) deepen the scope of the debate

to relevant economic, technical and social issues instead of confining them to legal procedures

and precedents; and (3) provide for an effective appeal mechanism. On the latter, the ERC could

hire more “arbitrators and “conciliators” akin to those at the National Labor Relations and

Conciliation (NLRCC) Board and the Construction Board rather than requiring all cases to be

heard by the Commission and immediately appealed to the Courts. In addition, a single panel of

experts, with a permanent chair and varying members depending on the issue on hand could be

formed to resolve disputes between the regulator and market agents and among market agents.

The dispute settlement mechanism of WESM, GMC and DMC could be constituted as sub-groups

reporting to this Experts’ Panel when the issues arise from or are within their jurisdictions.

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ph electric power industry market and policy assessment

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