Ngcp Draft Determination

Regulatory Reset for the

National Grid Corporation of the Philippines (NGCP)

for 2011 to 2015

DRAFT DETERMINATION

ERC Case No. 2009–180RC

15 July 2010

[THIS PAGE LEFT BLANK INTENTIONALLY]

Republic of the Philippines

Energy Regulatory Commission

Pacific Center, San Miguel Avenue, Pasig City

REGULATORY RESET

for the

NATIONAL GRID CORPORATION OF THE PHILIPPINES

(NGCP)

for

2011 to 2015

DRAFT DETERMINATION

Pursuant to Section 43(f) of Republic Act No. 9136, otherwise known as the Electric Power Industry Reform Act of 2001, and Rule 15, Section 5(a) of its Implementing Rules and Regulations the Energy Regulatory Commission (ERC) promulgated the Guidelines on the Methodology for Setting Transmission Wheeling Rates on May 29, 2003. These were subsequently updated and revised on September 16, 2009 as the Rules for Setting Transmission Wheeling Rates for 2003 to around 2027 (RTWR).

Under Section 7.1.2 of the TWRG and the subsequent RTWR, the ERC was required to publish a Regulatory Reset Issues Paper to provide the ERC’s initial views on the issues to be discussed during the pending Regulatory Reset Process, and to specify the information required to be delivered by the National Grid Corporation of the Philippines (NGCP) for the purposes of the Regulatory Reset Process and the time by which such information should be delivered. The Issues Paper dated February 16, 2009, was published. Following consultation on the Issues Paper, the ERC’s final view on the Regulatory Reset Process was described in the Position Paper dated September 9, 2009.

In accordance with the RTWR and the Issues Paper, NGCP filed various information and data relating to the information and data requirements for the Regulatory Reset Process with the ERC by June 25, 2010.

Under Section 7.1.7 of the RTWR, after consideration of the information provided by the Regulated Entity and the reports prepared by its Regulatory Reset Experts, the ERC is required to publish a Draft Determination on the Maximum Allowed Revenue that will apply to the Regulated Entity for the Third Regulatory Period. This document presents the ERC’s Draft Determination, based on the outcomes of its analysis to date.

Submissions are sought on this Draft Determination. Details of the required format and the time of submissions, as well as the schedule for legal processes on the Draft Determination, are provided in Section 2.3 of the document.

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REGULATORY RESET for the

NATIONAL GRID CORPORATION OF THE PHILIPPINES (NGCP)

for 2011 to 2015

DRAFT DETERMINATION

TABLE OF CONTENTS

1. Executive Summary .................................................................................................. 1 1.1 ERC PRELIMINARY FINDINGS ...................................................................................... 1

1.2 REVENUE SMOOTHING ................................................................................................... 3

1.3 ERC ADJUSTMENTS ......................................................................................................... 4

1.4 SIDE CONSTRAINTS ......................................................................................................... 6

1.5 ERC PRELIMINARY FINDINGS ...................................................................................... 6

1.6 ERC PRELIMINARY FINDINGS ...................................................................................... 7

1.7 PIS PARAMETERS ............................................................................................................. 9

1.8 PIS WEIGHTINGS ............................................................................................................. 10

1.9 GRID PLANNING ............................................................................................................. 11

1.10 ANCILLARY SERVICES ................................................................................................. 11

2. Introduction ............................................................................................................. 12 2.1 LEGAL BASIS ................................................................................................................... 12

2.2 OVERVIEW OF THE REGULATORY RESET PROCESS ............................................ 12

2.3 SUBMISSIONS ON THE DRAFT DETERMINATION ................................................. 13

2.4 CONFIDENTIALITY OF INFORMATION ..................................................................... 14

2.5 REGULATED ENTITY ..................................................................................................... 14

2.6 OBJECTIVE OF REGULATING ELECTRICITY TRANSMISSION SERVICES ........ 15

2.7 FORM OF REGULATION ................................................................................................ 16

2.8 EXCLUDED SERVICES ................................................................................................... 17

2.9 ERC ANALYSIS - EXCLUDED SERVICES ................................................................... 18

2.10 ERC PRELIMINARY FINDINGS – EXCLUDED SERVICES ...................................... 19

3. Review of Second Regulatory Period .................................................................... 21 3.1 INTRODUCTION .............................................................................................................. 21

3.2 DEMAND ........................................................................................................................... 21

3.3 PERFORMANCE INCENTIVE SCHEME ....................................................................... 24

3.4 REVENUE UNDER-RECOVERY – SMOOTHING ERROR ......................................... 28

3.5 REVENUE UNDER-RECOVERY – DEMAND FORECAST ........................................ 29

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3.6 REVENUE UNDER-RECOVERY – PERFORMANCE INCENTIVES ......................... 30

3.7 ERC ANALYSIS – REVENUE UNDER-RECOVERIES. ............................................... 30

3.8 ERC PRELIMINARY FINDINGS – REVENUE UNDER-RECOVERIES .................... 31

3.9 TAXATION ........................................................................................................................ 32

3.10 ERC ANALYSIS – INCOME TAX ADJUSTMENT ....................................................... 33

3.11 ERC PRELIMINARY FINDINGS – INCOME TAX ADJUSTMENT ........................... 34

3.12 ERC ANALYSIS – OTHER TAXES ................................................................................ 35

3.13 ERC PRELIMINARY FINDINGS – OTHER TAXES ..................................................... 36

3.14 SUMMARY OF TRANSITIONAL REVENUE ADJUSTMENTS ................................. 36

3.15 CAPEX IN SECOND REGULATORY PERIOD ............................................................. 37

3.16 OPEX IN SECOND REGULATORY PERIOD ................................................................ 37

4. Target Performance in the Third Regulatory Period .......................................... 39 4.1 INTRODUCTION .............................................................................................................. 39

4.2 DEMAND FORECAST...................................................................................................... 39

4.3 ERC ANALYSIS – DEMAND FORECAST. ................................................................... 40

4.4 ERC PRELIMINARY FINDINGS – DEMAND FORECAST ......................................... 42

4.5 PERFORMANCE INCENTIVE SCHEME ....................................................................... 42

4.6 ERC ANALYSIS – PERFORMANCE INCENTIVE SCHEME ...................................... 43

4.7 ERC PRELIMINARY FINDINGS – PERFORMANCE INCENTIVE SCHEME .......... 45

4.8 FORECAST CAPEX .......................................................................................................... 47

4.9 ERC ANALYSIS – CAPEX FOR RAB ASSETS ............................................................. 48

4.10 ERC PRELIMINARY FINDINGS - CAPEX FOR RAB ASSETS .................................. 50

4.11 ERC ANALYSIS – CAPEX FOR RESIDUAL SUBTRANSMISSION ASSETS .......... 51

4.12 ERC PRELIMINARY FINDINGS – FORECAST CAPEX ............................................. 52

5. Revenue Requirement in Third Regulatory Period ............................................. 54 5.1 INTRODUCTION .............................................................................................................. 54

5.2 FORECAST OPEX ............................................................................................................. 54

5.3 ERC ANALYSIS – FORECAST OPEX FOR RAB ASSETS .......................................... 55

5.4 ERC ANALYSIS – TRANSCO OPEX ............................................................................. 56

5.5 ERC ANALYSIS – OPEX FOR RESIDUAL SUBTRANSMISSION ASSETS ............. 57

5.6 ERC DRAFT DECISION – FORECAST OPEX ............................................................. 57

5.7 REGULATORY ASSET BASE ......................................................................................... 59

5.8 INITIAL ASSET VALUATION ........................................................................................ 59

5.9 ERC ANALYSIS – ASSET BASE RELATED ADJUSTMENTS ................................... 61

5.10 ERC ANALYSIS – CWIP FACTOR ................................................................................. 61

5.11 ERC ANALYSIS – INITIAL ASSET VALUATION ....................................................... 63

5.12 ERC ANALYSIS – ASSET DISPOSALS ......................................................................... 65

5.13 ERC DECISION ASSET DISPOSALS ............................................................................. 66

5.14 ERC ANALYSIS – ROLL FORWARD CAPEX .............................................................. 66

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5.15 ERC PRELIMINARY FINDINGS – OPENING REGULATORY ASSET BASE ......... 66

5.16 WEIGHTED AVERAGE COST OF CAPITAL ............................................................... 67

5.17 WORKING CAPITAL ....................................................................................................... 86

5.18 ERC ANALYSIS – WORKING CAPITAL ...................................................................... 87

5.19 ERC PRELIMINARY FINDINGS ON WORKING CAPITAL ....................................... 87

5.20 ERC PRELIMINARY FINDINGS - RETURN ON ASSET BASE ................................. 87

5.21 OTHER TAXES ................................................................................................................. 88

5.22 ERC ANALYSIS – OTHER TAXES ................................................................................ 88

5.23 ERC PRELIMINARY FINDINGS – OTHER TAXES ..................................................... 89

5.24 NATIONAL FRANCHISE TAX ....................................................................................... 90

5.25 FORCE MAJEURE EVENTS ............................................................................................ 90

5.26 ERC ANALYSIS – FORCE MAJEURE EVENTS ........................................................... 90

5.27 ERC PRELIMINARY FINDINGS – FORCE MAJEURE EVENTS ............................... 91

5.28 NET EFFICIENCY ADJUSTMENTS ............................................................................... 91

5.29 ERC PRELIMINARY FINDINGS ON NET EFFICIENCY ADJUSTMENTS .............. 92

6. Calculation of Allowed Revenue ............................................................................ 94 6.1 UNSMOOTHED REVENUE - REAL ............................................................................... 94

6.2 INFLATION ASSUMPTIONS .......................................................................................... 97

6.3 UNSMOOTHED REVENUE - NOMINAL ...................................................................... 97

6.4 SIDE CONSTRAINTS ....................................................................................................... 99

6.5 REVENUE SMOOTHING ................................................................................................. 99

6.6 ESTIMATED POWER DELIVERY SERVICE RATES ................................................ 101

7. Other Issues ........................................................................................................... 103 7.1 NETWORK PLANNING ................................................................................................. 103

7.2 SYSTEMS OPERATIONS AND ANCILLARY SERVICES ........................................ 104

7.3 REOPENING THRESHOLD ........................................................................................... 105

Appendix A: Revenue Carryover Analysis……………...…………………...…..106

Appendix B: Breakdown of ERC Approved CAPEX Forecast…………….….109

Appendix C: Breakdown of Opening RAB………………………………………110

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FIGURES

Figure No. Figure Description Page

1.1 Unsmoothed Maximum Annual Revenue 1

1.2 Comparison of ERC’s Preliminary Findings on Maximum Allowed Revenue with Revenue Application and 2006 Final Determination

2

1.3 Estimated Power Delivery Service Rates 3

1.4 Possible Revenue Paths 4

1.5 Comparison of ERC’s Preliminary Findings on Capital Expenditure with Revenue Application and 2006 Final Determination

6

1.6 Performance Incentive Scheme Profile – Positive Measure 10

1.7 Performance Incentive Scheme Profile – Negative Measure 10

3.1 PIS Profile – Positive Measure (SA, FLC, VLC) 27

3.2 PIS Profile – Negative Measure (SISI, FOT) 27

3.3 Historic CAPEX 38

3.4 Historic OPEX 39

4.1 Luzon Forecast Peak Demand 41

4.2 Visayas Forecast Peak Demand 41

4.3 Mindanao Forecast Peak Demand 42

4.4 Comparison of Historic and Forecast CAPEX 49

4.5 Comparison of ERC Approved CAPEX on RAB Assets with Regulated Entity’s Actual and Forecast CAPEX

52

4.6 Comparison of ERC Approved CAPEX on All Assets with Regulated Entity’s Actual and Forecast CAPEX

54

5.1 Comparison of Historic and Forecast OPEX 56

5.2 Comparison of ERC Allowed OPEX with Actual OPEX and Revenue Application Forecast

59

5.3 Yield Curve for Philippines Treasury Bills and Bonds for February 2010 71

5.4 Yield Curve for US 10-year US Dollar Treasury Bonds for February 2010 72

5.5 US Inflation Rate 73

5.6 Philippines Inflation Rate 74

5.7 Philippines CRP 75

5.8 Summary of Regulatory WACC Estimate 80

6.1 Comparison of ERC’s Preliminary Findings on MAR with Revenue Application and 2006 Final Determination

96

6.2 ERC Preliminary Findings compared with Revenue Application 98

6.3 Components of Unsmoothed Maximum Allowed Revenue 98

6.4 Possible Smoothed Revenue Paths 100


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TABLES

Table Number Table Description Page

1.1 Unsmoothed Maximum Allowed Revenue 1

1.2 Comparison of ERC’s Allowed Revenue with Revenue Application 5

1.3 ERC Preliminary Findings on CAPEX 6

1.4 Comparison of New and Current Performance Incentive Scheme Targets 9

1.5 Performance Incentive Scheme Parameters for the Third Regulatory Period 11

1.6 Weightings of Performance Incentive Scheme Measures 12

3.1 Inflators for Converting Actual Historic Expenditures from Nominal to Real, 2010 22

3.2 Inflators for Converting Forecast Historic Expenditures from Nominal to Real, 2010 22

3.3 Comparison of Actual and Forecast Peak Demand 24

3.4 Weightings of Performance Measures 28

3.5 Performance Measure Targets 28

3.6 Actual Performance 29

3.7 Total PIS Rewards 29

3.8 Revenue Requirement for the Second Regulatory Period 30

3.9 Side Constraints for the Second Regulatory Period 30

3.10 Revenue Under-recoveries during Second Regulatory Period 31

3.11 Revenue Shortfall to be Carried Through to the Third Regulatory Period 33

3.12 Tax Provisions for the Second Regulatory Period 33

3.13 Actual and Budgeted Tax Payments for the Second Regulatory Period 34

3.14 Calculation of ITA 35

3.15 Basis for Allocation of Other Tax Expenditure to RAB Assets 37

3.16 Derivation of Adjustment for Other Taxes 37

3.17 Transitional Revenue Adjustments 37

3.18 Historic CAPEX 38

3.19 Historic OPEX 39

3.20 Historic OPEX Discrepancies 49

4.1 ERC Preliminary Findings – Demand Forecasts 43

4.2 Comparison of New and Current PIS Targets 45

4.3 Network Elements in the ConA and ConSISI Indicators 46

4.4 PIS Parameters for the Third Regulatory Period 47

4.5 Weightings of PIS Measures 47

4.6 Forecast CAPEX 49

4.7 Forecast CAPEX for Land Purchase and ROW 50

4.8 ERC Approved CAPEX – RAB Assets 51

4.9 CAPEX for Residual Subtransmission Assets 53

4.10 ERC Approved Forecast CAPEX –All Assets 53

5.1 Forecast OPEX 55

5.2 Residual Subtransmission OPEX Forecast 58

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Table Number Table Description Page

5.3 ERC Allowed OPEX 59

5.4 Revenue Application Adjustments to SKM’s Initial RAB Asset Valuation 61

5.5 ERC Adjustments to SKM’s Initial RAB Asset Valuation 64

5.6 Regulated Entity Changes to SKM’s Initial Asset Valuation 65

5.7 Roll Forward of Initial Asset Valuation 68

5.8 Average US Inflation Rate to end January 2010 73

5.9 Average Philippines Inflation Rate to end January 2010 74

5.10 Overseas Transmission Company Equity and Asset Betas 77

5.11 Return on Equity using CAPM Formulae 79

5.12 Regulatory WACC Summary 81

5.13 Professor van Zijl’s Regulatory WACC Estimate 85

5.14 ERC Preliminary Findings on Working Capital 87

5.15 ERC Preliminary Findings on Return on Asset Base 87

5.16 Revenue Application Forecast for Other Taxes 88

5.17 ERC Preliminary Findings on Other Taxes 89

5.18 Force Majeure Event Claims 90

5.19 Derivation of Approved CEA 92

5.20 Derivation of Approved OEA 93

6.1 ERC Preliminary Findings on Maximum Allowed Revenue for Third Regulatory Period (real)

94

6.2 Revenue Application – Maximum Allowed Revenue for Third Regulatory Period 94

6.3 Comparison of ERC’s Maximum Allowed Revenue with Revenue Application 95

6.4 Assumed Change in Philippines CPI 97

6.5 ERC Preliminary Findings on Maximum Allowed Revenue for Third Regulatory Period (nominal)

97

6.6 Derivation of Approved MAR 96

6.7 Possible Smoothed Revenue Paths 100


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GLOSSARY OF ABBREVIATIONS Abbreviation Description

ACCC Australian Competition and Consumer Commission

AER Australian Energy Regulator

BIR Bureau of Internal Revenue

BSP Bangko Sentral ng Pilipinas

CAPEX Capital Expenditure

CAPM Capital Asset Pricing Model

cct-km Circuit-kilometers

CEA Capital Efficiency Adjustment

ConA Congestion Availability

ConSISI Congestion System Interruption Severity Index

CPI Consumer Price Index

CRP Country Risk Premium

CWIP Construction Work in Progress

DOE Department of Energy

DU Distribution Utility

EIU Economist Intelligence Unit

EPIRA Electric Power Industry Reform Act

ERC Energy Regulatory Commission

FDC Finance During Construction

FLC Frequency Limit Compliance

FME Force Majeure Event

FOT Frequency of Tripping

GFC Global Financial Crisis

IRR Implementing Rules and Regulations

ITA Income Tax Adjustment

kV kilovolt

kW kilowatt

LECG London Economics Consulting Group

MAR Maximum Allowed Revenue

MRP Market Risk Premium

MVAr MegaVolt Ampere reactive

MW MegaWatt

MWh MegaWatt hour

NEA Net Efficiency Adjustment

NGCP National Grid Corporation of the Philippines

NPC National Power Corporation

NPV Net Present Value

NSO National Statistics Office

OATS Open Access Transmission Services

ODRC Optimized Deprival Replacement Cost

OEA Operations and Maintenance Efficiency Adjustment

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Abbreviation Description

OPEX Operations and Maintenance Expenditure

PBR Performance Based Regulation

PDS Power Delivery Service

PEZA Philippines Economic Zone Authority

PIS Performance Incentive Scheme

PwC PricewaterhouseCoopers

PwC FA PricewaterhouseCoopers Financial Advisors

RAB Regulatory Asset Base

RDWR Rules for Setting Distribution Wheeling Rates

RORB Return on Rate Base

ROW Right of Way

RTWR Rules for Setting Transmission Wheeling Rates

SA System Availability

SCADA System Control and Data Acquisition

SIR System Interruption Reporting

SISI System Interruption Severity Index

SKM Sinclair Knight Merz

SMAR Smoothed Maximum Allowed Revenue

SPD System Peak Demand

TAMRP Tax Adjusted Market Risk Premium

TransCo National Transmission Corporation

TWRG Transmission Wheeling Rate Guidelines

US United States

VAT Value Added Tax

VLC Voltage Limit Compliance

WACC Weighted Average Cost of Capital

WC Working Capital

WESM Wholesale Electricity Spot Market

WUC Works Under Construction

Draft Determination - NGCP

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1. EXECUTIVE SUMMARY

MAXIMUM ALLOWED REVENUE

1.1 ERC Preliminary Findings

The unsmoothed maximum revenue that the Regulated Entity will be allowed to recover during the Third Regulatory Period, broken down into the separate building blocks, is shown in Table 1.1 and Figure 1.1. This preliminary findings represent a reduction of about 37% in the total revenue applied for in the Revenue Application.

Table 1.1: Unsmoothed Maximum Allowed Revenue (PhP million, nominal)

2010 2011 2012 2013 2014 2015

OPEX - 5,945.42 6,653.89 6,908.43 8,027.62 7,769.74

Return of capital (depreciation) - 6,619.46 6,999.55 7,008.58 6,830.21 6,893.76

Return on capital - 23,428.36 24,370.84 25,061.29 25,321.20 25,138.13

Real property taxes and VAT - 954.53 894.63 793.14 771.04 615.75

Force majeure adjustment - 284.08 - - - -

Net efficiency adjustment - (1,954.62) (4,015.94) (3,847.73) (4,081.99) (2,290.20)

Second Regulatory Period under-recoveries1 - 936.77 926.83 953.93 979.01 1,012.44

Total - 36,214.00 35,829.80 36,877.64 37,847.08 39,139.62

Total amount requested by Regulated Entity 20,622.00 55,626.30 59,346.90 62,082.90 64,580.60 64,531.50

Note 1: The ERC has allowed PhP3,314.09 million (real, 2010) net under-recovered revenue from the Second Regulatory Period. These have been carried through to the Third Regulatory Period as a separate adjustment.

Figure 1.1: Unsmoothed Maximum Annual Revenue (PhP million, nominal)


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The ERC’s allowed revenue does not include the 3% national franchise tax that NGCP must now pay in accordance with RA 9511. As this tax is levied on total revenue rather than income, the ERC has decided that this should be recovered through a surcharge on its customer invoices.

The allowed revenue includes revenues associated with the operation of residual subtransmission assets. This is in accordance with Resolution No 1, Series of 2009, where the ERC resolved that these assets would be added to the transmission regulatory asset base as of January 1, 2011.

Figure 1.2 provides a comparison of these preliminary findings with the Revenue Application with the Regulated Entity’s allowed and actual expenditure in the Second Regulatory Period. In order to allow a valid comparison across two regulatory periods, all revenues have been converted to real, 2010 for the purposes of this diagram.

Figure 1.2: Comparison of ERC’s Preliminary Findings on Maximum Allowed Revenue with Revenue Application and 2006 Final Determination (PhP million, real 2010)

The ERC’s estimated average power delivery service charges for the Third Regulatory Period, based on the total maximum allowed revenue shown in Table 1.1, are shown in Figure 1.3.


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Figure 1.3: Estimated Power Delivery Service Rates (PhP/kW/month, nominal)

1.2 Revenue Smoothing

Section 5.13 of the RTWR requires the maximum allowed revenue to be smoothed to reduce the likelihood of price shocks to customers and of revenue shocks to the Regulated Entity. The smoothing process uses the 2010 allowed revenue, which is constrained by the impact of side constraints, as the starting point. In applying the smoothing formula it is possible to adjust the allowed revenue stream while ensuring that the net present value of the revenues that the Regulated Entity is allowed to earn over the regulatory period does not change. There are two parameters that the ERC can change in the smoothing formula.

• The P0 factor, which is applied to the 2010 maximum allowed revenue. Adjusting the P0 factor has the effect of raising or lowering the revenue that the Regulated Entity can earn in the first year of the regulatory period.

• The X factor, which impacts the amount the maximum annual revenues can change from one year to the next relative to inflation. A positive X factor implies a progressive reduction in annual revenues relative to inflation while a negative X factor implies a progressive increase.

Figure 1.4 shows a range of price paths that are consistent with the ERC’s decision on the maximum allowed revenues. It shows that a high P0 factor will lower the initial revenue requirement but will also require a high X factor to allow these foregone revenues to be recovered in later years. The ERC is seeking feedback from stakeholders on their preferred revenue path. However it believes that an X factor of about 4% will be appropriate as this will allow revenues to remain relatively constant in nominal terms.


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Figure 1.4: Possible Revenue Paths

1.3 ERC Adjustments

In arriving at its preliminary findings on the maximum allowed revenue, the ERC made a number of adjustments to the analysis submitted by the Regulated Entity to support its Revenue Application. These adjustments are summarized in Table 1.2. The most significant adjustments are discussed further below.

• The ERC used a weighted average cost of capital of 13.63% whereas the Revenue Application used 19%. The ERC’s weighted average cost of capital is based on its analysis of market conditions at the end of February and will be updated prior to the issue of the Final Determination.

• The ERC limited the under-recovery of revenue resulting from the application of side constraints during the Second Regulatory Period to 5% of the accumulated revenue under-recoveries in 2010. This adjustment is consistent with the provisions of Clause 5.14.2 of the RTWR.

• The ERC applied negative adjustments totaling PhP 14.32 billion (real, 2010) under the efficiency carryover provisions in Section 5.17 of the RTWR. The Regulated Entity’s final analysis on efficiency carryover was not submitted until April 2010 and the adjustment in the Revenue Application was provisional only.


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Table 1.2: Comparison of ERC’s Allowed Revenue with Revenue Application (PhP million, real 2010)

Total Revenue (2010-15)

Variance Remarks Revenue

Application Preliminary

Findings

Second Regulatory Period revenue shortfall (Table 3.11) 29,800.00 15,044.42 (49.5%)

The ERC limited recovery of revenues as a consequence of actual demand being lower than the forecast. Recovery of revenues relating to the P0 adjustment and the PIS was allowed.

Recovery of income tax provision (Table 3.14) (8,142.00) (12,839.41) (57.7%)

The ERC did not allow recovery of the income tax provision relating to the disallowed revenue recovery.

Adjustment for other taxes (1,036.00) 1,109.08

The ERC did not allow recovery of the excess provision for other taxes in 2006-08 as this is not provided for in the RTWR.

OPEX 36,142.92 31,101.86 (13.9%)

The ERC adopted the recommendation of NCL. The Draft Determination includes OPEX relating to residual subtransmission assets.

Return of capital (depreciation) 34,508.77 30,424.54 (11.8%)

Return on capital 191,092.58 109,114.25 (42.9%)

The allowed WACC was 13.63% compared to 19% in the Revenue Application. Other factors included reductions in the CAPEX forecast and the disallowance of a CWIP factor, consistent with the regulatory approach in other jurisdications1. CWIP was included in the RAB.

Other taxes 7,555.53 3,599.55 (52.4%)

Includes VAT but excludes the 3% national franchise tax, which the ERC has decided will be recovered outside the MAR.

Force majeure adjustment 483.03 272.37 (43.6%) Allowed under ERC Case No. 2007-148-RC only.

Net efficiency adjustment 673.87 (14,322.59)

The ERC accepted NCL’s recommendation that many of the proposed adjustments to the 2006 Final Determination forecasts should not be accepted.

Total 291,078.69 163,504.07 (43.8%)

CAPEX2 80,779.97 44,368.93 (45.0%)

The ERC has accepted NCL’s recommendations on CAPEX reductions. The preliminary findings includes CAPEX on residual subtransmission assets but excludes ROW and other land related CAPEX, which the ERC has decided will be recovered during the Fourth Regulatory Period following an ex post prudency review

Note 1: While the RTWR provides for a CWIP factor, this requires CAPEX to be presented on an “as commissioned” rather than “as spent” basis. Note 2: Provided for information only as CAPEX is not a MAR building block.


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1.4 Side Constraints

The ERC sees no basis for changing the existing side constraint of CPI+2%.

CAPITAL EXPENDITURE


The ERC’s preliminary findings on the capital expenditure (CAPEX) that the Regulated Entity will be allowed to recover during the Third Regulatory Period, broken down into the separate building blocks, is shown in Table 1.3. This preliminary findings represents a reduction of 45% on the CAPEX applied for in the Revenue Application, although it excludes all land related CAPEX (which comprised almost 14% of the forecast CAPEX on transmission assets), and also the estimated value added tax component of the forecast. If land and estimated VAT costs are removed from the NGCP forecast, the reduction would have been approximately 33%.

Table 1.3: ERC Preliminary Findings on CAPEX (PhP million, nominal)

2011 2012 2013 2014 2015

ERC Preliminary Findings 13,755.90 13,616.83 10,518.84 7,015.61 4,097.24

Revenue Application (including residual subtransmission assets) 31,768.36 21,186.25 17,179.38 10,582.59 7,742.03

Revenue Application (excluding estimated VAT &land) 27,675.81 17,294.28 13,942.21 8,319.00 5,743.80

In Figure 1.5 the allowed CAPEX is compared with the Revenue Application forecast and also with the allowed and actual CAPEX for the Second Regulatory Period. In order to allow valid comparisons across two regulatory periods all expenditures have been converted to PhP real 2010.

Figure 1.5: Comparison of ERC’s Preliminary Findings on Capital Expenditure with Revenue Application and 2006 Final Determination (PhP million, real 2010)


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The major adjustments made to the forecast in the revenue application were as follows:

• The ERC has adopted a lower peak demand forecast as the basis for determining CAPEX requirements than was used in the Revenue Application. Approximately half the demand growth forecast at the time of the 2006 Final Determination has not materialized and this is the main reason why transmission rates during the Second Regulatory Period were determined by the side constraints rather than the revenue requirement. The use of the lower demand forecast has resulted in the deferral of grid development projects in Luzon and Mindanao.

• The ERC considered that some individual project costs were high and adjusted these down accordingly.

• As indicated above, the ERC has removed all land purchase and ROW costs from the Revenue Application forecast. There is a high level of uncertainty in respect of both the magnitude and timing of ROW settlement costs (which form the major component of this expenditure item) and this makes it difficult to assess the reasonableness of the Regulated Entity’s forecasts. The ERC has decided that it will allow the Regulated Entity to recover all actual and reasonable land related CAPEX, together with the appropriate return on investment, during the Fourth Regulatory Period after these costs have been validated by an ex-post prudency review at the time of the next Reset.

• The ERC has also removed the estimated VAT component of the CAPEX forecast. It has decided that the Regulated Entity must account for VAT as a separate tax. This will address problems that would otherwise arise with the asset valuation for the Fourth Regulatory Period.

PERFORMANCE INCENTIVE SCHEME


The performance incentive scheme is intended to provide the Regulated Entity with an incentive to improve the level of service provided to the grid. It provides a reward over and above the allowed revenue for providing a good quality service and applies a penalty if the service is poor.

The ERC’s preliminary findings on the performance incentive scheme (PIS) is to include all indicators used in the PIS for the Second Regulatory Period but to set more stringent targets for most measures. It is anticipated that this will lead to continuing improvements in the quality of supply delivered by the Regulated Entity.

The ERC has also decided to extend the PIS by including the following three new indicators into the scheme:


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• an indicator (ConA) that measures the availability of a subset of lines and transformers on the Luzon grid. The network elements to be included have been specified by the ERC because they are considered critical to the successful operation of WESM and to the avoidance of congestion on the grid;

• an indicator (ConSISI) that measures the potential impact of outages on this same subset of lines and transformers. For this measure the impact is determined by the load being carried by a network element at the time of an interruption and the total length of the interruption; and

• a customer engagement indicator that measures the level of compliance of the Regulated Entity with the requirement in Clause C3.2 of the revised OATS Rules to publish on its web site advance notice of a planned supply interruption or a planned outage of a grid component. The indicator measures the average number of days advance notice that is given and is reported separately for each of the three main grids.

For the Third Regulatory Period, the maximum reward or penalty that can be applied is 3% of the maximum allowed revenue for 2011. As data is not expected to be immediately available to establish a reasonable target for the ConSISI indicator, this will not be introduced until January 1, 2013.

A comparison of the Second Regulatory Period targets with the Third Regulatory Period targets is shown in Table 1.4. The indicators are of two types. For a positive indicator a higher measure indicates better reliability while, for a negative indicator, a lower measure is better.

Table 1.4: Comparison of New and Current Performance Incentive Scheme Targets

Second Regulatory Period Proposed

NEGATIVE INDICATORS

Luzon

System Interruption Severity Index (SISI) 17.08 9.92

Frequency of Tripping (FOT) 7.88 4.63

Visayas

SISI 272.80 55.75

FOT 7.00 4.14

Mindanao

SISI 61.59 12.83

FOT 9.55 5.52

POSITIVE INDICATORS

Luzon

System Availability (SA) 99.19 99.40

Frequency Limit Compliance (FLC) 99.95 99.97

Voltage Limit Compliance (VLC) 81.06 93.35

Visayas

SA 99.05 99.65


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FLC 98.73 98.73

VLC 99.55 99.55

Mindanao

SA 99.08 99.62

FLC 99.84 99.95

VLC 98.42 99.74

1.7 PIS Parameters

For each performance measure the ERC must prescribe a dead band, a collar and a cap. The target is the center of the dead band. If actual performance against the measure is within the dead band there is no reward or penalty. A reward or penalty is applied on a pro rata basis if the actual performance lies between the dead band and the cap or collar. Outside this region the reward or penalty is limited to the maximum that can be applied to that measure. This is illustrated in Figures 1.6 and 1.7.

Figure 1.6 Performance Incentive Scheme Profile – Positive Measure

Performance

Deadband

Pen

alty

/ B

onus

Php 0

Collar

Cap

Targetχ σ1 σ2σ2− σ1−

Performance

Deadband

Pen

alty

/ B

onus

Php 0

Collar

Cap


Figure 1.7 Performance Incentive Scheme Profile – Negative

Measure

Performance

Deadband

Pen

alty

/ B

onus

Php 0

Cap

Collar


Performance

Deadband

Pen

alty

/ B

onus

Php 0

Cap

Collar



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The performance incentive scheme parameters that will be applied to the different performance measures in the Third Regulatory Period are shown in Table 1.5

Table 1.5: Performance Incentive Scheme Parameters for the Third Regulatory Period

Collar (Penalty

Deadband Cap (Reward) Low High

Luzon

SISI 22.24 17.96 9.39 5.10

FOT 5.30 4.96 4.29 3.95

SA 99.08 99.19 99.42 99.53

FLC 99.93 99.95 99.99 100.002

VLC 89.60 90.93 93.59 94.92

ConA3 To be determined

ConSISI4 To be determined

SIR3 1 7 14 20

Visayas

SISI 157.40 121.83 50.69 15.12

FOT 9.20 7.45 3.94 2.19

SA 99.44 99.52 99.68 99.75

FLC 96.24 97.49 99.98 1002

VLC 97.52 98.53 100 -1

SIR 1 7 14 20

Mindanao

SISI 34.74 30.74 22.74 18.74

FOT 7.98 6.75 4.28 3.04

SA 99.44 99.53 99.70 99.78

FLC 99.66 99.76 99.96 100.002

VLC 99.59 99.66 99.82 99.89

SIR 1 7 14 20 Note 1: No reward applies as maximum measure (100%) is within the dead band. Note 2: As the maximum possible level of reliability is within one standard deviation of the dead band boundary

the maximum reward available for this performance indicator is reduced on a pro rata basis. Note 3: Positive indicator Note 4: Negative indicator.

1.8 PIS Weightings

Weightings are needed to determine the proportion of the total available reward or penalty to apply to each measure. The weightings to be applied for the Third Regulatory Period are shown in Table 1.6.


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Table:1.6: Weightings of Performance Incentive Scheme Measures Indicator

Weightings Grid Weightings

Luzon Visayas Mindanao

SISI 25% 20% 50% 30%

FOT 25% 34% 33% 33%

SA 20% 34% 33% 33%

FLC 5% 34% 33% 33%

VLC 5% 34% 33% 33%

ConA 5%1 100% - -

ConSISI 5%1 100% - -

SIR 10% 34% 33% 33% Note 1: Prior to January 1, 2013, the weighting applied to the ConA indicator will be 10% and the weighting

applied to the ConSISI indicator will be 0%

OTHER ISSUES

1.9 Grid Planning

The Regulated Entity’s approach to grid planning does not appear to be in the best interest of consumers as it does not ensure the minimization of the total cost of electricity. The ERC therefore requires the Regulated Entity to review its approach to grid planning to ensure that it supports this objective. On completion of the review, the Regulated Entity is directed to provide the ERC with a copy of the review findings and advise the ERC of the actions that it intends to take in response to these findings.

1.10 Ancillary Services

The ERC is proposing to extend the performance incentive scheme to include an indicator related to the procurement of ancillary services. To this end, it seeks input from stakeholders on the definition and possible parameters of a suitable indictor.

Comments on the development and implementation of a suitable PIS measure should be provided by interested parties at the same time as other written comments on this Draft Determination. The ERC will also develop its own proposal, which it will release during the public consultation hearings on this Draft Determination. Stakeholders will then have an opportunity to provide written comments on the ERC proposal. Should the ERC decide to implement and additional performance indicator, full details will be provided in the Final Determination.


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2. INTRODUCTION

2.1 Legal Basis

2.1.1 Section 43 (f) of Republic Act No. 9136, otherwise known as the “Electric Power Industry Reform Act of 2001” (EPIRA), and Rule 15, Section 5 (a) of its Implementing Rules and Regulations (IRR), authorized the Energy Regulatory Commission (ERC) to adopt alternative forms of internationally-accepted rate-setting methodology. Pursuant to the aforementioned provisions of law, after conducting public consultations, the ERC adopted on September 16, 2009 the Rules for Setting Transmission Wheeling Rates1 (RTWR). The RTWR provides for Performance Based Regulation (PBR) using a revenue cap to determine the maximum rates that may be charged by the Regulated Entity to its customers for the provision of Regulated Transmission Services2. It amends the Guidelines on the Methodology for Setting Transmission Wheeling Rates3 (TWRG) adopted by the ERC on May 29, 2003, which formed the basis for setting the revenue cap that applied over the period January 1, 2006 to December 31, 2010 (the Second Regulatory Period).

2.1.2 The ERC is currently conducting a Regulatory Reset Process (Reset) in accordance with Article 7 of the RTWR to set the maximum allowed revenue (MAR) that will be used to determine the maximum rates the Regulated Entity may charge its customers for the provision of Regulated Transmission Services over the period January 1, 2011 to December 31, 2015 (the Third Regulatory Period).

2.2 Overview of the Regulatory Reset Process

2.2.1 In accordance with Clause 7.1.2 of the TWRG, on February 11, 2009 the ERC issued a document entitled Regulatory Reset for the National Transmission Corporation (TransCo) for 2011 to 2015, Issues Paper4 (Issues Paper) to provide its initial views on the issues in the pending Reset, to specify the information required to be delivered by the Regulated Entity for purposes of the Reset and to indicate the procedure to be undertaken by the ERC for purposes of the Reset.

2.2.2 After receiving written submissions on the Issues Paper in accordance with Clause 7.1.4 of the TWRG, on September 9, 2009 the ERC issued a document entitled Regulatory Reset for the National Grid Corporation of the Philippines (NGCP) for 2011 to 2015, Position Paper5 (Position Paper) that provided the ERC’s views on some of the primary inputs and approaches to be used for the Reset.

1 Rules for Setting Transmission Wheeling Rates for 2003 to around 2027; ERC, September 16,

2009. 2 The services that constitute Regulated Transmission Services are defined in the Glossary

(Clause 1.3) of the RTWR. 3 Guidelines on the Methodology for Setting Transmission Wheeling Rates for 2003 to around

2027; ERC, May 29, 2003. 4 Regulatory Reset of the Regulated Transmission Services for 2011 to 2015, Issues Paper;

ERC, February 16, 2009. 5 Regulatory Reset of the National Grid Corporation of the Philippines (NGCP) for 2011 to

2015, Position Paper; ERC, September 9, 2009.


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2.2.3 On December 18, 2009, the National Grid Corporation of the Philippines (NGCP) submitted its application (Revenue Application) with the ERC for the approval of the MAR for the Third Regulatory Period. Annex A6 of this filing provides background information in support of the Revenue Application. This application has been docketed as ERC Case Number 2009-160RC. The ERC has subsequently held a number of expository and evidentiary hearings on the case in Manila, Cebu and Davao.

2.2.4 This Draft Determination is issued in accordance with Clause 7.1.7 of the RTWR and provides the ERC’s preliminary views on the MAR that will apply for the provision of Regulated Transmission Services during the Third Regulatory Period.

2.3 Submissions on the Draft Determination

2.3.1 Submissions are invited on this Draft Determination. Any person other than the applicant and parties of record who wants to participate in the public consultation may file comments in writing to the ERC which contains among others, the name and address of such person and concise statements of the comments and the ground relied upon.

2.3.2 For the public consultations, the applicant and parties of record may file in writing, any comments, questions, suggested modifications to data sources, and any other issues pertaining to this Draft Determination in writing addressed to the Energy Regulatory Commission, 16th Floor, Pacific Center Building, San Miguel Avenue, Ortigas Center, Pasig City and through electronic mail sent to [email protected] on or before August 6, 2010. Any other interested person shall file his/her comments within the same period previously mentioned.

2.3.3 Parties, who do not wish to participate in the public consultations, are also welcome to make submissions. Such submissions shall be submitted in the same format as that described above and at the same date.

2.3.4 The ERC hereby sets this matter for initial public consultation at the following dates and times:

• August 17, 2010 - Davao City

• August 18, 2010 - Manila

• August 20, 2010 - Cebu City

Although this consultation is open to the public, only parties of record who have filed written comments will be allowed to participate in the discussions. Should there be time towards the end of the public consultation for verbal comments from other persons who have interest in the proceedings, this shall be allowed by the Commissioner in charge of public consultation. Parties of record are not required to have an attorney present but are strongly encouraged to have technical experts present with knowledge of accounting, finance, economics, engineering and pricing issues.

6 Submission to the Energy Regulatory Commission (ERC) on the Regulatory Reset

Requirements for the Third Regulatory Period under the Rules for Setting Transmission Wheeling Rates for 2003 to around 2027; National Grid Corporation of the Philippines (NGCP), December 18, 2009.


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2.3.5 To ensure that the public consultations progress in an efficient and timely manner, the ERC intends to provide in advance to parties of record a summary of the issues raised and comments made in the submissions. Where such issues can be addressed or answered directly, this will be noted in the summary. It should be noted that the public consultation is not intended to be a forum for merely repeating issues raised or comments made in the written submissions – all interested parties have access to read the submissions. The public consultation is intended to allow parties of record the opportunity to highlight the key aspects of their submissions and to afford the ERC and parties of record the opportunity to discuss submissions.

2.4 Confidentiality of Information

2.4.1 In terms of Clause 7.1.4 of the RDWR, where a written submission identifies some confidential information, the ERC may only publish or otherwise disclose that information if it has given written notification to this effect to the person or party who has made the submission and the party has not objected in writing to such publication or disclosure within two weeks of receiving written notification. After reviewing the objection, the ERC may decide to still publish or disclose the information, giving one week’s advance notice to the affected party.

2.5 Regulated Entity

2.5.1 At the time the ERC issued its Final Determination for the Second Regulatory Period, (2006 Final Determination) Regulated Transmission Services were provided by the National Transmission Corporation of the Philippines (TransCo). Under RA 9551, which was signed by the President on December 1, 2008, a nationwide franchise to manage the transmission system was granted to NGCP. The Act became effective on January 15, 2009.

2.5.2 NGCP has signed a Concession Agreement with TransCo, which covers the management and development of the transmission grid over the term of the franchise. Under the Concession Agreement, NGCP is responsible for the operation, management and development of the grid while TransCo continues to hold title over the transmission assets. Notwithstanding this, TransCo continues to be responsible for the settlement of Rights of Way (ROW) claims in respect of projects that were ongoing at the time RA 9551 became effective, while NGCP is responsible for ROW claims for projects that were initiated subsequent to the effectivity of the Act.

2.5.3 Hence, while NGCP will incur the bulk of the costs of providing Regulated Transmission Services over the Third Regulatory Period, some residual costs for the provision of these services will be incurred by TransCo. For the purposes of this Regulatory Reset Process, the ERC is concerned only with the total costs of providing the Regulated Transmission Services and not with who incurs these costs. Hence, for the purposes of this Regulatory Reset Process the ERC is treating NGCP and TransCo as if they were part of a single Regulated Entity. How the revenues derived from the provision of Regulated Transmission Services are distributed between the two parties is an internal matter that does not need to be addressed in this Draft Determination.


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2.6 Objective of Regulating Electricity Transmission Services

2.6.1 Electricity transmission is an essential component of the provision of an electricity supply in a modern economy. However, the provision of transmission services is a natural monopoly due to the high barriers to entry, which are a consequence of the high cost and long lives of the specialized fixed assets required to provide the service, as well as the high cost and limited availability of the ROW over which these assets are constructed. For these reasons the Regulated Entity is the only provider of transmission services in the Philippines. Hence, it is not subject to the constraints on its pricing that it would experience if a number of alternative providers competed to provide a transmission service to customers.

2.6.2 Regulation is intended to ensure that the provision of a transmission service is sustainable and provided with the quality demanded by customers for a price that is comparable to that which the provider would be able to charge for a similar service in a more competitive environment.

2.6.3 Sustainability requires ongoing investment to develop the transmission grid to meet increased demand for electricity and rising customer expectations of quality, and also to replace existing assets that have reached the end of their economic life. Sustainability therefore requires that the investor is able to earn a return that is comparable to that it would achieve if its funds were invested in alternative enterprises available in the market with a similar investment risk profile. If the return offered is inadequate, there is a risk that the investor will divert funds elsewhere and that the quality of the transmission service provided will deteriorate as a result. The consequences of insufficient investment in the power system are already being experienced in the Philippines in the power outages resulting from shortages of generation in some parts of the country.

2.6.4 Quality of supply requires efficient operation and maintenance practices in order to reduce the probability of network faults occurring. In addition, as faults cannot be completely eliminated, it requires a degree of redundancy to be built into the network so that electricity supply to customers is maintained after a fault does occur. The quality of supply provided by the transmission network in the Philippines is poor when compared to that of both developed and other developing countries. This is due, in part, to the fact that there has been insufficient historical investment in the grid and, as a result, the level of redundancy required to maintain supply following a fault is not available in many areas.

2.6.5 Criteria for developing the network to ensure an acceptable quality of supply are set out in the Philippine Grid Code (PGC). The ERC is aware that significant capital investment is required to bring the network up to the standard required in the Grid Code and that, if this investment is implemented too quickly, customers could experience a severe rate shock. While it may be necessary to spread this investment over more than one regulatory period in order to manage this impact, there is a risk of further deterioration in supply reliability if the MAR is so low, that the required investment does not occur.

2.6.6 Efficient pricing requires the skilful management of costs, both the costs of capital investment and the costs of operating and maintaining the network.


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Managing the cost of capital investment requires ensuring that new capital investment projects are effectively designed and prioritized, implemented no earlier than actually required and that project delivery costs are minimized. Managing operations and maintenance costs involves the development and implementation of systems that ensure that necessary maintenance is identified and undertaken before service issues arise and that systems are in place to minimize the cost of back office and administrative support.

2.6.7 As labor costs form a major component of both capital expenditure (CAPEX) and operations and maintenance expenditure (OPEX), efficient pricing requires that labor costs are actively managed. This involves not only the management of employee and contractor salaries and benefits, but also the management of staff and contractor numbers to ensure that they reflect the minimum number required to provide the level of service demanded by customers.

2.7 Form of Regulation

2.7.1 PBR is an internationally acceptable method of rate setting that meets the requirements of Section 43(f) of EPIRA. It is similar to that used in the United Kingdom, Australia, some states of the US, New Zealand and Singapore and is designed to promote the objectives of electricity transmission regulation described in Section 2.5 above.

2.7.2 Unlike the earlier Return on Rate Base (RORB) approach, PBR is forward looking and sets the MAR that the Regulated Entity can earn from the provision of Regulated Transmission Services in advance of each five year regulatory period. This provides an incentive for cost reduction because, as revenues are set in advance, the Regulated Entity is able to retain any cost savings it is able to make until after the end of each regulatory period. Over time this leads to price efficiency, since savings made in one regulatory period are built into the cost structure used to determine the MAR that will apply over the subsequent regulatory period, resulting in prices to the customer that are lower than they would otherwise have been.

2.7.3 The return that the Regulated Entity can earn on its investment in transmission system assets is equal to the Weighted Average Cost of Capital (WACC). This is set by the ERC during each Reset, based on a market analysis of the return a business in the Philippines with a similar risk profile to the Regulated Entity can be expected to earn.

2.7.4 The RTWR includes a Performance Incentive Scheme (PIS) that provides the Regulated Entity an incentive to improve the quality of service provided to customers. Under the PIS, key indicators of service performance are monitored annually. If the quality of service delivery is above the targets set during the Reset, the Regulated Entity can earn an incentive of up to 3% of MAR. Conversely, if the quality of service falls below the targets, a penalty of up to 3% of MAR can be applied. The PIS is intended to focus grid management strategies on the quality of service delivery and to ensure that the quality of supply delivered to customers does not suffer through a lack of investment and poor grid operation and maintenance.


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2.8 Excluded Services

2.8.1 This Draft Determination is concerned with determining the MAR that the Regulated Entity can earn from the provision of Regulated Transmission Services as defined in Clause 1.3 of the RTWR. However, both NGCP and TransCo are engaged in the provision of services that are additional to the provision of Regulated Transmission Services and earn additional revenues for providing these services7.

2.8.2 NGCP’s excluded services currently include the provision of Transmission Connection Services8, and the management of Residual Subtransmission Assets9. In addition NGCP provides the following services that utilize part of the Regulated Asset Base (RAB).

• Rental of facilities and equipment; and

• Co-location. This includes interconnection services, antenna attachments, use of building lots and space, use of access roads, attachment of telephone cables, and tapping to AC/DC power sources.

2.8.3 NGCP also earns revenue from provision of the following services that do not involve the use of RAB assets10.

• Technical assistance, including assisting with the testing, commissioning, calibration and maintenance of clients’ facilities; and

• Conduct of grid impact studies for existing and prospective grid users.

In Section 3.9 of Annex A of the Revenue Application, the Regulated Entity submits that, consistent with its earlier filings, these services do not utilize assets from the RAB and hence are outside the MAR.

2.8.4 As noted in Section 2.4 above, TransCo continues to exist, notwithstanding the passing of RA 9511 and the signing of the Concession Agreement. Its functions include:

• Management of the Concession Agreement;

• Provision of consultancy and other technical services for the management of the power distribution systems of the Philippine Economic Zone Authority (PEZA);

• Management of the divestment of residual subtransmission and connection assets to qualified distribution utilities (DUs) in accordance with the relevant provisions of Section 8 of EPIRA; and

7 Services provided by the Regulated Entity that earn revenues outside of the MAR are referred to as excluded services. 8 Transmission Connection Services are defined in Clause 1.3 of the RTWR. The cost of providing these services is

recovered through a separate connection charge in accordance with Annex IV, Module F of the OATS Rules. 9 Residual Subtransmission Assets are defined in Clause F(AIV)6.1 of the OATS Rules 2006. In accordance with

Clause 2 of ERC Resolution No 18, Series of 2009, these assets will be added to the Regulated Asset Base of the Regulated Entity if they have not been sold to qualified distribution utilities by December 31, 2010. The Residual Subtransmission Charge described in Clause F(AIV)5.1 of the OATS Rules 2006 will then no longer be applied and revenue requirement for the management of these assets will be included in the calculation of the MAR covered by this Draft Determination.

10 As the RAB is comprised only of Regulated Transmission Assets, these assets are also referred to in this Draft Determination as RAB Assets.


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• Settlement of ROW claims for projects that had commenced prior to the effectivity of RA 9511 in accordance with the provisions of Clause 5.08(b) of the Concession Agreement.

2.9 ERC Analysis - Excluded Services

2.9.1 The MAR covered by this Draft Determination covers only the provision of Regulated Transmission Services. The building block methodology set out in the RTWR requires that the MAR be equal to the efficient costs of providing these services (including the provision of a reasonable return on the investment in Regulated Transmission Assets). In order to meet the objectives of the RTWR, it is therefore necessary for costs associated with the provision of excluded services to be identified and excluded from the analysis. As the costs of excluded services are recovered elsewhere, inclusion of these costs in the analysis used to determine the MAR will result in the costs being recovered twice, providing a windfall gain to the Regulated Entity.

2.9.2 Forecast costs for the provision of Transmission Connection Services have been separately identified in the Revenue Application and have been excluded from the forecast costs of providing Regulated Transmission Services. These costs will be recovered through the connection charge that is levied on transmission customers in accordance with Annex IV, Module F of the Open Access Transmission Services (OATS) Rules.

2.9.3 Forecast costs for the provision of Residual Subtransmission Services have also been identified in the Revenue Application. As noted in footnote 10, the ERC has resolved that these assets will be included in the RAB as of December 31, 2010 and the residual subtransmission charge will no longer be applied. Hence all costs associated with the provision of these services will need to be included in the MAR. In the Revenue Application the Regulated Entity has included residual subtansmission assets in the RAB as of 1 January 2011. It has also identified the OPEX associated with these assets11 but has not included this OPEX in its modeling to determine the MAR for the Third Regulatory Period.

2.9.4 No adjustment has been made in the Revenue Application for revenues received from services that utilize assets that form part of the RAB. Under Section 20 of EPIRA, a portion not exceeding 50% of the net income derived from such related businesses should be used to reduce the transmission wheeling rate. This provision in EPIRA is accounted for by the term RBRt in the under/over recovery formula in Clause 5.3.3 of the RTWR. This has the effect of reducing the MAR in a particular regulatory year by the portion of the previous year’s related business revenue approved by the ERC. Hence, this adjustment is outside the scope of this Draft Determination.

2.9.5 As noted in paragraph 2.7.3 above, NGCP also receives revenue from the provision of technical assistance and the conduct of grid impact studies. In past rate filings NGCP has submitted that, as such revenue does not utilize RAB assets, it is not covered by the provisions of Section 20 of EPIRA. However, while such services do not utilize RAB assets, they are provided by

11 Annex A, Table 9.2.


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NGCP staff, whose costs may have already been fully recovered through the MAR. Hence if no adjustment was made to the MAR to offset such revenues, there would be a windfall gain to NGCP since the costs of providing such services would be recovered twice.

2.9.6 If the ERC was to treat the provision of technical assistance and grid impact studies as “outside the MAR” as submitted by NGCP it would be necessary to forecast the cost of providing these services and exclude them from the costs used to determine the MAR in order to avoid this double recovery. However, the demand for these services can vary significantly from year to year and is therefore difficult to forecast in advance. The alternative approach, currently used by the ERC, of reducing the MAR in a particular regulatory year by an amount based on the revenues received in the previous year from the provision of these services achieves the required outcome and avoids potential forecasting error.

2.9.7 The Revenue Application does not include any TransCo costs or revenues associated with the management of the Concession Agreement or with the provision of consultancy and other technical assistance associated with the management of PEZA power distribution systems. However it includes OPEX associated with the divestment of Residual Subtransmission and Connection Assets and both OPEX and CAPEX associated with the settlement of ROW claims associated with projects that were initiated prior to the effectivity of RA 9511.

2.9.8 It is not clear why the Regulated Entity has classified the management of the process for divesting Residual Subtransmission and Connection Assets as a Regulated Subtransmission Service. While the divestment has been mandated by EPIRA the assets involved are not currently classified as Regulated Transmission Assets. There is no reason management of the divestment process should not be funded from the revenue received from the sale of the assets. It is noted that Residual Subtransmission Assets will become Regulated Transmission Assets on January 1, 2011 and divestment of these assets will cease as of this date.

2.9.9 The settlement of ROW claims associated with the construction of Regulated Transmission Assets is clearly a Regulated Transmission Service, irrespective of which party undertakes the work on behalf of the Regulated Entity. It is noted that NGCP is providing this service for new projects. While the OPEX incurred by TransCo for the management of this process is included in the MAR, the treatment of CAPEX payments incurred in settling ROW claims is discussed in Section 4.9.

2.10 ERC Preliminary Findings – Excluded Services

2.10.1 The ERC will not remove forecast costs for the provision of technical assistance and the conduct of grid impact studies from the OPEX used as a basis for determining the MAR. Nevertheless it reaffirms that these are excluded services and it will continue, through the annual rate setting process, to ensure that there is no double recovery of these costs by reducing the allowed MAR for a particular regulatory year in accordance with the revenue received over the previous year for the provision of these services.


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2.10.2 The ERC will allow the Regulated Entity to recover the forecast OPEX costs for the operation of Residual Subtransmission Assets during the Third Regulatory Period. An adjustment has been made in calculating the allowed OPEX, as these costs were not included in the OPEX forecast in the Revenue Application.

2.10.3 The ERC does not consider the divestment of Transmission Connection Assets to be a Regulated Transmission Service and has excluded these costs from the allowed MAR in this Draft Determination.


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3. REVIEW OF SECOND REGULATORY PERIOD

3.1 Introduction

3.1.1 This chapter reviews the performance of the Regulated Entity over the Second Regulatory Period and compares this performance with the forecast or target performance at the time of the Final Determination.

3.1.2 In order to provide a valid comparison of financial indicators, actual and forecast expenditures over the Second Regulatory Period have been converted to real PhP at the end of 2010. As this is also the base used for determining forecast expenditures over the Third Regulatory Period, this approach will allow a valid comparison of expenditure levels across the two regulatory periods. Actual expenditures over the Second Regulatory Period have been inflated to real 2010 peso using the actual changes in the Consumer Price Index (CPI) as shown in Table 3.1. For the 2010 regulatory year, the CPI forecast of the Economist Intelligence Unit (EIU) as of February 2010 has been used.

Table3.1: Inflators for Converting Actual Historic Expenditures from Nominal to Real, 2010

2005 2006 2007 2008 2009 2010

Actual Inflation Rate - 6.24% 2.83% 9.31% 3.23% 3.80%

Inflator 1.280 1.204 1.171 1.071 1.038 1.000

3.1.3 Forecast expenditures in the 2006 Final Determination12 require a different treatment because the forecast CPI at the time the Final Determination was written was different from what actually occurred. These expenditures have therefore been deflated back to real 2005 levels using the CPI assumed in the Final Determination. The real 2005 expenditures have then been inflated to 2010 using the actual CPI inflation rates. This process is shown in Table 3.2.

Table 3.2: Inflators for Converting Forecast Historic Expenditures from Nominal to Real 2010

2005 2006 2007 2008 2009 2010

Assumed Inflation Rate in 2006 Final Determination - 7.30% 5.60% 4.60% 3.90% 4.30%

Deflator to 2005 Real 1.000 0.932 0.883 0.844 0.812 0.779

Actual Inflation Rate - 6.24% 2.83% 9.31% 3.23% 3.80%

Inflator 2005 real to 2010 Real 1.280 1.280 1.280 1.280 1.280 1.280

Inflator – Forecast Nominal to 2010 Real - 1.192 1.129 1.080 1.039 0.996

3.2 Demand

3.2.1 The major difference between the RTWR, which applies to regulated electricity transmission services, and the Rules for Setting Distribution

12 Regulatory Reset for the National Transmission Corporation (TransCo) for 2006 to 2010, Final Determination.

ERC Case No 2005 – 041RC; Energy Regulatory Commission, June 13, 2006.


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Wheeling Rates (RDWR), which applies to the regulated electricity distribution services provided by investor owned DUs, is that regulated transmission services are subject to a revenue cap whereas regulated distribution services are subject to a price cap. Under a revenue cap it is the maximum revenue that is controlled by the regulatory arrangements whereas under a price cap it is the maximum average price. Hence, under a revenue cap it is the customers that take volume risk – if actual demand is lower than forecast at the time of the reset, then customers must pay more, conversely if demand is higher, customers will pay less. This contrasts with the situation under a price cap, where the price is set by the regulator and does not change with volume – if the volume of sales change, the revenue received by the business will also change but the average price paid by customers will not be affected.

3.2.2 This difference in the regulatory treatment of transmission and distribution businesses is consistent with international practice and is a result of differences in the nature of the CAPEX projects undertaken by the two types of utility. A high proportion of the CAPEX program undertaken by a transmission utility involves large projects with long implementation times and high costs. As a result, it must plan and develop its network to meet medium and long term demand growth forecasts with a higher degree of uncertainty. Hence, if a transmission utility were to operate under a price cap, it might be reluctant to invest in network augmentations because of a risk that forecast revenues would not be achieved. If such a situation was to lead to a lack of investment, customers would suffer because development of the grid would not occur and the quality and reliability of supply could deteriorate. A revenue cap mitigates this risk as forecast revenues are guaranteed.

3.2.3 These risks are not as great for a distribution utility, where a large proportion of the CAPEX is of an incremental nature, driven largely by the growth in demand of individual customers. Hence, it is much easier for a distribution utility to adapt its CAPEX program in accordance with changes in short term demand expectations.

3.2.4 An issue with a revenue cap is that there is a strong incentive for a regulated entity to submit an excessively high demand forecast in order to drive a high CAPEX requirement, which would in turn result in a higher revenue cap. If such a forecast is accepted, customers could provide revenue to the regulated entity in excess of what is really needed. A secondary outcome could be poor CAPEX decision making because the expenditure constraints that would exist in a more competitive environment are not present.

3.2.5 TransCo recognized these risks at the time it filed its revenue application for the Second Regulatory Period. It stated13:

TransCo is very conscious that the demand forecast eventually endorsed by the ERC will have a significant influence on the regulated price path. As noted later in this report, however, under the revenue cap form of regulation contained in the TWRG, the possibility of

13 Quote from Clause 2.7.1 of the ERC’s Final Determination. See footnote 13 for source

reference.


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significant forecast error represents an important financial risk for TransCo. Notwithstanding this consideration, TransCo has opted for a responsible and conservative forecast of future growth.

In the course of the expert review of the CAPEX forecast, TransCo significantly modified its forecast of future demand growth from a high growth scenario to a more conservative growth profile…

3.2.6 In this context it is appropriate to review that actual electricity demand over the Second Regulatory Period and to compare this with the demand forecast submitted by TransCo in its revenue application for the Second Regulatory Period and also and with the demand forecast accepted by ERC in its 2006 Final Determination. This analysis is presented in Table 3.3.

Table 3.3: Comparison of Actual and Forecast Demand (MW) 2006 2007 2008 2009

Luzon

TransCo Forecast 6,747 7,014 7,290 7,574

ERC Approved 6,728 6,981 7,252 7,552

Actual 6,466 6,643 6,674 7,036

Difference1 (4.16%) (5.29%) (8.45%) (7.10%)

Visayas


ERC Approved 1,154 1,214 1,289 1,364

Actual 997 1,102 1,176 1,241

Difference1 (14.57%) (11.27%) (11.11%) (11.92%)

Mindanao


ERC Approved 1,293 1,363 1,440 1,525

Actual 1,228 1,241 1,204 1,327

Difference1 (8.63%) (13.46%) (21.46%) (19.18%)

Philippines2


ERC Approved 9,175 9,558 9,981 10,441

Actual 8,691 8,986 9,054 9,604

Difference1 (6.12%) (7.27%) (10.76%) (9.61%) Note 1: Difference between actual demand and TransCo forecast. Note 2: Non-coincident demand

3.2.7 Table 3.3 shows that actual demand over the first four years of the Second Regulatory Period has been consistently lower than TransCo’s “responsible and conservative” forecast at the time of the reset, to the extent that, over the relatively short four year period14, approximately two year’s forecast demand growth has not materialized. TransCo could argue, with justification, that the situation has arisen because demand growth has been reduced by the unforeseen global financial crisis and also that actual demand in Visayas and

14 At the time of preparing this Draft Determination, peak demands for 2010 were not

available.


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Mindanao could not be fully supplied because of the shortage of generation. Notwithstanding this, the ERC notes that under an unconstrained revenue cap model without any regulatory intervention, customers end up paying for such forecasting errors and the Regulated Entity remains relatively immune.

3.2.8 It follows that, where a high demand forecast is used as the basis of determining the required CAPEX, the risk to the Regulated Entity is minimized but at the same time the risk of customers being required to provide revenue that is not needed is increased. Conversely, if an artificially low demand forecast is used as the basis for setting the revenue cap, the Regulated Entity carries a higher risk; nevertheless customers also carry the risk of deteriorating supply reliability driven by a lack of investment. Within the framework of the RTWR, and acknowledging the conflicting drivers, the ERC must strive to achieve an outcome that will serve the best interests of customers by providing, over the long term, an electricity supply with an acceptable level of reliability at an efficient price. An optimal outcome will not be achieved if a forecast on the high side of a range of possible demand outcomes is accepted uncritically.

3.3 Performance Incentive Scheme

3.3.1 As noted in Paragraph 2.6.4, the PIS provides the Regulated Entity an incentive to improve the quality of service provided to customers. During the Second Regulatory Period, if the quality of service delivery was above the targets set during the Reset, the Regulated Entity could earn an annual incentive of up to 3% of the 2006 MAR. Conversely, if the quality of service fell below the targets, a penalty of up to 3% of the 2006 MAR could be applied.

3.3.2 The following indicators were used as components of the Second Regulatory Period PIS. (a) System Interruption Severity Index (SISI) – measures the ratio of the unserved energy

to the system peak load15:

(b) Frequency of Trippings per 100cct-km (FOT) – measures the number of forced line outages (both transient and sustained) per 100 cct-km initiated by the automatic tripping of protection relays:

15 SISI is measured in hours for each supply interruption and all supply interruptions are accumulated over the

measuring period. In measuring the delivery point unserved energy, it is assumed that demand at the point of interruption would have remained constant over the duration of the interruption at the level that existed at the time of the interruption.

SISI = Total Delivery Point Unserved Energy (MWh)

System Peak Load (MW)

FOT = Total Number of Trippings

; for voltage level 69kV and above Circuit Length per 100 cct-km


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(c) System Availability (SA) or circuit availability as a proportion of total circuit time – refers to the availability or percentage of the system being considered to be on-line during the evaluation period:

( ) ( ) ( ) ( )[ ]%x

PN

OECODC...OECODCOECODCOECODCPNSA

n

inn

1001332211

•

−++−+−+−−•=

∑=

Where:

SA = System Availability, in %

N = Total number of components16

P = Period covered, in minutes17

n = Total number of components on outage

i = Component on outage

ODC = Outage Duration of Component, in minutes

OEC = Outage Exemption of Component18

(d) Frequency Limit Compliance (FLC) – refers to the percentage of time during the rating period that the system frequency is within the allowable range of 60 ± 0.3 Hz:

Where:

NF = total number of frequency limit violations. R = scanning rate of the SCADA/EMS, in seconds (2 secs. in Luzon

starting 2012). d = number of days in rating period.

(e) Voltage Limit Compliance (VLC) – refers to the percentage of the number of voltage measurements during the rating period that the voltage variance did not exceed ± 5% of the nominal voltage of all busses (Luzon – 230 kV & 500 kV, Visayas – 230 kV/138 kV, Mindanao – 138 kV) monitored at the high side of the substation. Monitoring time at peak load hours of 11 am, 2 pm and 7 pm and off-peak hour at 2 am. These hours represent the times when the bus voltages are expected to be not at their normal levels.

16 A component refers to critical transmission line or power system equipment e.g. transformer. For the purposes of

the PIS, each grid (Luzon, Visayas, Mindanao) is treated separately. 17 For the purposes of the PIS, the measurement is undertaken and reported across a calendar year. 18 Default is zero. Values depend on the exemptions as referred to the outage classification currently implemented by

NGCP in accordance with TransCo Corporate Circular No. 2003-50 and its Implementing Rules and Regulations.

SA = The sum for all circuit hours available

(Number of circuits) x (Number of hours in period)

FLC = [ 1 - (nf * r)

] x 100 (d * 24 * 60 * 60)


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Where:

NV = total number of frequency limit violations. ns = number of substations. d = number of days in rating period.

3.3.3 Performance was measured separately for each indicator on each grid, providing a total of fifteen (15) separate annual measures of grid performance. For each measure a target was set based on the average historic performance over the previous five years. A dead band of one standard deviation each side of the target performance level was set, where no reward or penalty applied. Outside of the dead band and up to a level of two standard deviations above or below the target, the reward or penalty was determined in a linear fashion, as shown in Figures 3.1 and 3.2. Hence a reward applied if the performance was materially better than the historic level, whereas a penalty applied if performance deteriorated significantly below the historic level.

Figure 3.1 PIS Profile – Positive Measure (SA, FLC, VLC)

Performance

Deadband

Pen

alty

/ B

onus

Php 0

Collar

Cap


Performance

Deadband

Pen

alty

/ B

onus

Php 0

Collar

Cap


Figure 3.2 PIS Profile – Negative Measure (SISI, FOT)

Performance

Deadband

Pen

alty

/ B

onus

Php 0

Cap

Collar


Performance

Deadband

Pen

alty

/ B

onus

Php 0

Cap

Collar


VLC = [ 1 - nv

] x 100 (d * 4 * ns )

Reward

Reward


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3.3.4 It was necessary to weight each of the fifteen (15) performance measures to determine what portion of the total available reward or penalty to apply to each measure. Measures were weighted separately by grid in accordance with Table 3.4. The actual weighting applied to a particular indicator can be determined by multiplying the indicator weighting with the relevant grid weighting.

Table 3.4: Weightings of Performance Measures

Indicator Grid


SISI 45% 20% 50% 30%

FOT 25% 32% 29% 39%

SA 10% 34% 33% 33%

FLC 10% 34% 33% 33%

VLC 10% 29% 36% 35%

3.3.5 The targets for each performance measure for the Second Regulatory Period, together with the dead band boundaries, collars and caps are shown in Table 3.5.

Table 3.5: Performance Measure Targets

Indicator Collar (Max. Penalty)

Dead Band Cap (Max Reward) Low Target High

Luzon

SISI 26.63 21.86 17.08 12.31 7.53

FOT 11.23 9.56 7.88 6.21 4.53

SA 98.94 99.06 99.19 99.32 99.44

FLC 99.85 99.90 99.95 100 -1

VLC 59.13 70.1 81.06 92.02 1002

Visayas

SISI 647.41 460.1 272.80 85.50 02

FOT 11.29 9.14 7.00 4.86 2.72

SA 98.75 98.90 99.05 99.20 99.35

FLC 96.24 97.49 98.73 99.98 1002

VLC 97.52 98.53 99.55 100 -1

Mindanao

SISI 135.16 98.37 61.59 24.81 02

FOT 16.43 12.99 9.55 6.12 2.68

SA 98.24 98.66 99.08 99.50 99.91

FLC 99.63 99.74 99.84 99.94 1002

VLC 96.44 97.43 98.42 99.41 1002 Note 1: No reward applies as maximum measure (100%) is within the dead band. Note 2: As the maximum possible level of reliability is within one standard deviation of the dead band boundary

the maximum reward available for this performance indicator is reduced on a pro rata basis.


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3.3.6 The actual performance of the Regulated Entity for each measure for each of the first four years of the Second Regulatory Period is shown in Table 3.6. Performances that earn a reward are shown in bold and those that incur a penalty are shown in italics. The remaining performances fall within the dead band for each indicator.

Table 3.6: Actual Performance 2006 2007 2008 2009

Luzon

SISI 7.54 10.26 9.54 28.70

FOT 5.25 4.17 3.99 4.27

SA 99.31 99.53 99.46 99.30

FLC 99.91 100.00 99.99 100.00

VLC 87.91 91.32 93.21 95.07

Visayas

SISI 33.55 39.91 83.56 208.32

FOT 4.25 4.13 4.54 3.63

SA 99.78 99.72 99.59 99.40

FLC 96.31 97.42 99.05 98.76

VLC 96.84 98.20 98.79 98.42

Mindanao

SISI 19.72 4.41 10.43 16.73

FOT 5.10 3.76 7.95 2.62

SA 99.77 99.67 99.34 99.57

FLC 99.96 99.11 99.94 99.50

VLC 99.60 99.93 99.80 99.80

3.3.7 It can be seen from Table 3.6 that the performance of the transmission network over the first four years of the Second Regulatory Period has been significantly better than its historic performance; to the extent that, notwithstanding the width of the dead band and the two measures for which no rewards are available, it has earned rewards on 63% of all measures. On the other hand, it has incurred penalties on only 13% of all measures. The rewards to which the Regulated Entity is entitled as a result of this performance improvement, as determined by the ERC in its annual rate decisions, are shown in Table 3.7.

Table 3.7: Total PIS Rewards (PhP million, nominal) 2007 2008 2009 2010

359.00 532.00 334.32 234.00

3.4 Revenue Under-Recovery – Smoothing Error

3.4.1 The MAR that the Regulated Entity could earn from the provision of Regulated Transmission Services during the Second Regulatory Period, was established in the ERC’s 2006 Final Determination. The process involved first determining an unsmoothed MAR based on the actual forecast revenues that TransCo would require during each year of the regulatory period. This unsmoothed revenue stream was then subject to a smoothing process in


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accordance with Section 4.13 of the RTWR in order. The unsmoothed and smoothed MAR (SMAR) for the Third Regulatory Period are shown in Table 3.8 below.

Table 3.8: Revenue Requirement for the Second Regulatory Period (PhP million, nominal)

2006 2007 2008 2009 2010

MAR 32,617.80 40,310.90 43,873.00 43,524.50 43,543.50

SMAR 35,611.60 37,249.80 38,590.80 39,710.00 41,020.50 Source: 2006 Final Determination, Figure 7.4

3.4.2 The smoothing process is intended to achieve an outcome that does not disadvantage the Regulated Entity by ensuring that the 2005 net present value (NPV) of the two revenue streams, when discounted by the allowed weighted average cost of capital (15.88% for the Second Regulatory Period) was the same. However, while the formulae in Section 4.13 of the RTWR were correctly applied, this outcome was not achieved. The NPV of the MAR revenue stream in Table 2.8 is PhP 131,339.65 million whereas the NPV of the SMAR revenue stream is only PhP 124,925.64 million. The adjustment for the difference in the two NPV’s is the P0 factor that appears in the revenue smoothing formula Clause 4.13.3 of the RTWR.

3.4.3 Mathematically the P0 component forms an adjustment to the MAR for the year prior to the beginning of the regulatory period (i.e. 2005 in the case of the Second Regulatory Period). Any difference between this adjusted MAR and the actual revenue received should have been carried forward into the first year of the subsequent regulatory period by way of the Kt factor in the price control formula in Clause 4.2.1 of the RTWR. The smoothing process undertaken for the 2006 Final Determination resulted in a P0 factor that, in effect, increased the 2005 revenue requirement by PhP6,415 million. In the rate setting process for 2006, this shortfall was not properly carried forward. The ERC accepts that a consequence of this error is that the MAR to which the Regulated Entity was entitled has been understated during the annual rate setting process over the Second Regulatory Period.

3.5 Revenue Under-Recovery – Demand Forecast

3.5.1 In order to limit the impact of increases in the transmission rate on individual customers, the ERC imposed side constraints in accordance with the Section 6.4 of the RTWR, which limited the annual increase in the rate individual customers could be charged19. The side constraints applied by the ERC during the Second Regulatory Period are shown in Table 3.9. Since the smoothing process limited the annual increase in the MAR to CPI-1%, these side constraints were at least 3% and up to 8% higher than the expected rate of revenue growth. The side constraints were therefore not expected to restrict the ability of ERC to set transmission wheeling rates that would fully recover the allowed revenue.

19 Order dated August 24, 2006 on ERC Case No. 2005-041RC.


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Table 3.9: Side Constraints for the Second Regulatory Period 2006 2007 2008 2009 2010

Side Constraint CPI + 2% CPI + 7% CPI + 5% CPI + 3% CPI +2% CPI = Consumer Price Index Source: ERC Order August 24, 2006, Case No 2005-041-RC; p4.

3.5.2 However, the ability of the Regulated Entity to earn revenue depends both on demand and on the transmission wheeling rate determined at the beginning of each year by the ERC. While the ERC permitted annual transmission wheeling rate increases up to the limit allowed by the side constraints, the Regulated Entity was unable to achieve its MAR in any year of the regulatory period primarily because, as shown in Table 3.3, the annual growth in demand was well below the growth rates assumed for the 2006 Final Determination.

3.6 Revenue Under-Recovery – Performance Incentives

3.6.1 Due to the fact that the Regulated Entity was unable to recover its allowed revenues because the rate increases permitted by the ERC, it also did not recover the PIS rewards to which it was entitled20. These are shown in Table 3.7.

3.7 ERC Analysis – Revenue Under-Recoveries

3.7.1 In order to determine the estimated accumulated level of revenue under-recoveries by the end of 2010, the ERC has reapplied the price control formula using the correct data. Three separate analyses have been undertaken.

1. The formula has been applied without considering the impact of the P0 error or the PIS adjustments to the allowed revenue. The accumulated under-recovery at the end of 2010 resulting from this analysis is due primarily to the impact of the demand forecast error discussed in Section 2.5 above.

2. The analysis was then repeated including the correct treatment of the P0 factor. The difference between the accumulated under-recovery in this analysis and that from the analysis described in subclause 1 above is due to the error in the application of the P0 factor.

3. Finally the full extent of the under-recovery was determined by a third analysis that also included the PIS adjustments to the allowed revenue. The difference between the total under-recovery and that from the analysis described in subclause 2 above can be attributed to the PIS under-recovery.

3.7.2 The accumulated under-recoveries estimated using the above analysis described above shown in Table 3.10 below. Tables providing more detail on how these under-recovers have been calculated are provided in Appendix A.

20 The PIS rewards were taken into account by ERC in its annual rate cases. However these decisions impacted only

the rate the regulated entity could charge and did not alter the revenue cap.


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Table 3.10: Revenue Under-recoveries during Second Regulatory Period (PhP million, real 2010)

Analysis Description Total Accumulated Under-recovery

Incremental Under-recovery

1. Side-constraints only 12,447.76 12,447.76

2. P0 under-recovery added 22,373.30 9,925.54

3. PIS under-recovery added 24,040.58 1,667.28

3.8 ERC Preliminary Findings – Revenue Under-Recoveries

3.8.1 The ERC acknowledges that the P0 adjustment in the 2006 Final Determination has not been recovered by the Regulated Entity as intended by the RTWR. It further acknowledges that the rewards and penalties for the PIS, as defined in Section 8 of the 2006 Final Determination were intended to adjust the MAR, whereas the PIS implementation during the Second Regulatory Period made no change to the MAR. Hence the Regulated Entity has not been rewarded as intended by the design of the PIS. The ERC will therefore allow the P0 and PIS under-recoveries to be passed through and fully recovered by the Regulated Entity. Failure to do so would be unduly onerous to the Regulated Entity and inconsistent with the intent of the PBR regime set out in the RTWR.

3.8.2 As noted in paragraph 3.5.1, the side constraints for the Second Regulatory Period were designed so they would not be a limiting factor in setting the transmission wheeling rate to allow the Regulated Entity to fully recover its ARR. In the event, due to the fact that the actual demand turned out to be so much lower than forecast at the time of the reset, the side constraints have come into play in setting the rate for each year of the regulatory period, to the extent that they have proved to be the major constraint on the amount of revenue that the Regulated Entity could earn.

3.8.3 As discussed in paragraph 3.2.4, there is a significant incentive for the Regulated Entity to present a high load forecast as the basis for a revenue application. While there is an element of hindsight in reaching this conclusion, it does appear that this was the case with the load forecast submitted by TransCo for the Second Regulatory Period. The ERC does not believe that customers should be unduly penalized for this forecasting error. Section 5.14.2 of the RTWR places an upper bound on the risk faced by customers by limiting the amount of the revenue under-recovery that may be carried forward to the Third Regulatory Period to 5% of the MAR for 2010. The ERC notes that, as shown in Table 3.9, it significantly relaxed the standard 2% side constraint over the period 2007-09. Notwithstanding this, the Regulated Entity was not able to achieve the constrained revenue set by the ERC in its rate determinations in of the first four years of the Second Regulatory Period.

3.8.4 Section 5.14.2 of the RTWR limits the revenue under-recovery that may be carried forward to the Third Regulatory Period to 5% of the MAR for 2010. This limit equates to 5% of PhP 69,032.0321 or PhP 3.451.60 million. While

21 This amount is derived in the analysis of Appendix A.


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the ERC has relaxed this requirement in respect of the under-recoveries of the P0 adjustment for the Second Regulatory Period and the PIS rewards, it considers that the reasons for doing so, as set out in paragraph 3.8.1, do not apply to under-recoveries arising from the shortfall in demand. It has therefore decided to limit the carry forward of this under-recovery to PhP 3,451.60 million.

3.8.5 The revenue shortfalls from the Second Regulatory Period that may carried forward to the Third Regulatory Period are shown in Table 3.11. These shortfalls are expressed in real 2010 PhP and will be incorporated into the determination of the MAR requirement for the Third Regulatory Period, as discussed in Section 6.3. They do not include any tax adjustments that will also be incorporated into the MAR.

Table 3.11: Revenue Shortfall to be Carried Through to Third Regulatory Period (PhP million, real 2010)

Description Incremental Under-recovery

Side-constraints. 3,451.60

P0 under-recovery. 9,925.54

PIS under-recovery. 1,667.28

Total 15,044.42

3.9 Taxation

3.9.1 The tax provisions included in the MAR for the Second Regulatory Period as set out in the 2006 Final Determination are shown in Table 3.12. The estimate of corporate income tax was based on an assumed income tax rate of 35% from 2006-08 and 30% in 2009-10, consistent with the provisions of the Philippines EVAT law. The MAR did not include any provision for value added tax (VAT) since it was assumed that VAT would be charged to customers over and above the transmission wheeling rate and that any VAT paid by the Regulated Entity on its inputs would be recovered through offsets against this income.

Table 3.12: Tax Provisions for the Second Regulatory Period (PhP million, nominal)

2006 2007 2008 2009 2010

Corporate income tax - 6,240.10 8,384.00 7,640.90 7,580.60

Other taxes 605.50 646.40 666.40 678.00 697.00

Total 605.50 6,886.50 9,050.40 8,318.90 8,277.60 Source: 2006 Final Determination, Table 7.4

3.9.2 The award of a national transmission franchise to NGCP upon the effectivity of RA 9511 on January 15, 2009, resulted in a significant change in the tax regime. Specifically:

• NGCP was no longer required to pay income tax. In its place it became liable for a national franchise tax, assessed at 3% of revenue.

• NGCP became exempt from VAT. This means that it is not required to add VAT to its invoices and does not have to remit VAT payments to the Bureau of Inland Revenue (BIR). However it is still required to pay VAT


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on the goods and services it procures from external sources. As this cost cannot now be offset against the VAT paid on its customer invoices to be passed through to the BIR, it must be recovered through the transmission wheeling rate.

• NGCP is also exempt from all other taxes and levies except real property tax.

3.9.3 In Annex A of the Revenue Application, the Regulated Entity summarized the actual and budgeted22 taxes paid during the Second Regulatory Period. These payments are summarized in Table 3.13.

Table 3.13: Actual and Budgeted Tax Payments for the Second Regulatory Period (PhP million, nominal)

2006 2007 2008 2009 2010

Corporate income tax - 7,955.74 4,817.76 1,610.97 -

National franchise tax - - - 1,077.40 1,333.80

Other taxes paid by TransCo 14.40 101.20 160.00 202.70 397.20

Property Taxes paid by NGCP - - - - 29.80

VAT on OPEX - - - 278.20 379.20

VAT on CAPEX - - - 1,203.50 1,202.90

Total 14.40 8,056.94 4,977.66 4,372.77 3,342.90 Source: 2011 Revenue Application, Annex A, Section 4.

3.10 ERC Analysis – Income Tax Adjustment

3.10.1 A comparison of Tables 3.12 and 3.13 shows that the actual income tax (including the national franchise tax on income) paid during the Second Regulatory Period was significantly lower than the income tax provision in the MAR for the period. The building block formula in Section 4.5.7 includes an Income Tax Adjustment (ITAt), which requires that any over- or under- payment of income tax during the Second Regulatory Period is recovered from (or returned to) customers during the Third Regulatory Period. Hence this under-payment of income tax during the Second Regulatory Period must be returned to customers.

3.10.2 The formula for calculating the ITA for the Third Regulatory Period is given in Section 5.12.2 of the RTWR. This formula annualizes the ITA so that it is expressed as five annual equal payments over the period. However, the ERC considers that the intent of the RTWR would be fully met if the income tax underpayments for each year of the Second Regulatory Period were accumulated through to 2010, on the basis implied by the formula in Section 5.12.2 of the RTWR and then returned to customers through an offset against the revenue under-recoveries that are still to be paid by customers and which are shown in Table 3.11.

3.10.3 In Section 4.6.3 of Annex A of its 2011 Revenue Application, the Regulated Entity submitted that the income tax provision in its revenue application was

22 As the Revenue Application was prepared in late 2009, payments made in 2009 and 2010 are

budgeted rather than actual.


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based on the MAR requirement in the 2006 Final Determination. As it was not able to fully achieve this MAR due to the error in the application of the P0 adjustment and the application of the side constraints, it recalculated its tax liability against its actual revenue from the provision of regulated transmission services and used this as a revised baseline for the calculation of the ITA. However it has also argued in Section 5 of Annex A of the Revenue Application that it should be allowed to fully recover all revenue shortfalls that occurred during the Second Regulatory Period. The ERC believes there is a logical inconsistency between these two arguments in that the income tax provision is an integral component of the MAR calculation in the 2006 Final Determination. It follows therefore that the tax provision in the Final Determination is the correct baseline for the calculation of the ITA if the ERC allows the MAR to be fully recovered. Any adjustment to this baseline should reflect only the tax payable on that portion of the MAR for which recovery is explicitly disallowed.

3.10.4 The recovery of the revenue provided for in the Second Regulatory Period is discussed in Section 3.8. The ERC’s decision is to allow the recovery of all revenue provided in the 2006 Final Determination except for PhP 8,995.16 million (real 2010)23, which the ERC decided should not be recovered because the actual demand on the grid was lower than the demand forecast at the time of the Final Determination. This equates to a reduction of PhP 3,025.39 million in the income tax provision based on the 2010 tax rate of 30% assumed in the 2006 Final Determination and assuming that the Regulated Entity’s costs are not affected by this decision.

3.11 ERC Preliminary Findings – Income Tax Adjustment

3.11.1 The calculation of the allowed ITA is shown in Table 3.14. Nominal amounts have been inflated to 2010 PhP using the numerator of the formula in Section 5.12. The formula used to convert the nominal adjustment to the 2010 present value is the same as that used by the Regulated Entity in Section 4.6.4 of Annex A of its Revenue Application.

Table 3.14: Calculation of ITA (PhP million) 2006 2007 2008 2009 2010

Corporate income tax provision in 2006 Final Determination (nominal) - 6,240.10 8,384.00 7,640.90 7,580.60

Less adjustment for disallowed revenue recovery (3,025.39)

Adjusted baseline (nominal) 6,240.10 8,384.00 7,640.90 4,555,21

Actual and budgeted tax paid

Actual and budgeted income tax (nominal) - 7,955.74 4,817.76 1,610.97

National franchise tax (nominal) - - - 1,077.40 1,333.80

Total tax paid (nominal) 7,955.74 4,817.76 2,688,37 1,333.80

ITA (nominal) - 1,715.64 (3,566.24) (4,952.53) (3,221.41)

23 This is the difference between the estimated under-recovery of PhP 12,447.76 million due to

the application of side constraints (Table 3.10) and the PhP 3,451.60 million this is allowed to be recovered (Table 3.11).


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ITA (2010 PV) (12,839.01)

3.12 ERC Analysis – Other Taxes

3.12.1 The building block formula in Section 4.5.7 of the RTWR includes a Taxm,t component that provides for the recovery of taxes other than corporate income tax. However the ITA component of the formula relates only to corporate income tax. Taxes other than corporate income tax are treated in a manner similar to OPEX, where the Regulated Entity is provided with an incentive to minimize its tax liability to the extent that it is legally possible to do so. It is able to retain any savings until the end of the current regulatory period, at which time ongoing savings will be passed through to customers as an outcome of the reset process.

3.12.2 Notwithstanding this, Article XI of the RTWR provides for an adjustment prior to the end of a regulatory period in the event of a Tax Event occurring. Consistent with the intent of the RTWR, the ERC has decided not to require recovery of the savings in taxes (other than corporate income tax) made over the period 2006-2009. However the tax changes that occurred with the effectivity of RA 9511 meet the criteria for a Tax Event and an adjustment for these two years is appropriate. The ERC does not accept the accuracy of the analysis presented in Annex A of the Revenue Application as it has identified the following issues.

• The approved taxation component of the Second Regulatory Period MAR presented in Table 4.12 of Annex A of the Revenue Application is taken from Table 7.3 of the 2006 Final Determination. This covered all taxes, whereas only those allocated to RAB assets (as presented in Table 7.4 of the 2006 Final Determination (and Table 3.12 above) should have been considered.

• It is not clear whether the other taxes paid by TransCo presented in Table 4.13 or the property tax paid by NGCP shown in Table 4.14 of Annex A of the Revenue Application relate to all assets or to RAB assets only. However, given the error made in presenting the provision in the Final Determination, it is likely that the amounts relate to all assets. The ERC has therefore reduced these amounts by the ratio of RAB assets to total assets as determined by Sinclair Knight Merz (SKM) in its final asset valuation report. This analysis is shown in Table 3.15.

• The Revenue Application did not indicate how the levels of VAT in OPEX and CAPEX for the period 2009-10 were estimated24. In particular, the VAT on CAPEX for 2009 (PhP 1,203.5 million) is 13.8% of the Regulated Entity’s actual and budget CAPEX for 2009 (as shown in Table 7.3 of the Revenue Application). This is in excess of the standard VAT rate of 12%. The ERC has therefore substituted its assessment of a reasonable VAT provision for these two years.

24 The Regulated Entity’s estimated VAT payments are shown in Table 4.14 of Annex A of the

Revenue Application.


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3.13 ERC Preliminary Findings – Other Taxes

3.13.1 The proportion of the expenditure on other taxes that the ERC has allocated to RAB assets is shown in Table 3.15. The values shown in the table are taken from the supplementary SKM asset valuation report25.

Table 3.15: Basis for Allocation of Other Tax Expenditure to RAB Assets

Values as at December 31, 2008 PhP million, real

ODRC value of RAB assets 151,188.47

ODRC value of residual subtransmission assets 13,351.63

ODRC value of connection assets 9,773.89

Total 174,313.99

Proportion allocated to RAB assets 86.73% Source: SKM.

3.13.2 ERC’s analysis to determine the adjustment for other taxes is shown in Table 3.16. The 2010 PV has been calculated using the same formula as used for the ITA shown in Table 2.14.

Table 3.16: Derivation of Adjustment for Other Taxes (PhP million) 2009 2010

Provision for other taxes in 2006 Final Determination1 (nominal) 678.00 697.00

Expenditure on other taxes (nominal)

Total expenditure on other taxes by TransCo and NGCP2 202.70 427.00

Expenditure on other taxes allocated to RAB assets 175.80 370.34

VAT on OPEX 326.06 325.00

VAT on CAPEX 373.66 729.64

Total expenditure on taxes 875.52 1,424.98

Adjustment 197.52 728.98

Adjustment for other taxes (2010 PV) 1,109.98 Note 1: Table 3.12 Note 2: Table 3.13

3.14 Summary of Transitional Revenue Adjustments

3.14.1 A summary of the revenue adjustments to be carried forward to the Third Regulatory Period is shown in Table 3.17. The adjustment is shown as a 2010 NPV and will be carried forward into the Third Regulatory Period using the methodology described in Section 6.3.

Table 3.17: Transitional Revenue Adjustments (PhP million) 2010 NPV

Revenue under-recoveries (Table 3.11) 15.044.42

ITA (Table 3.14) (12,839.01)

Adjustment for other taxes (Table 3.16) 1,109.98

25 Valuation of the Regulatory Asset Base of the National Grid Corporation of the Philippines;

Supplementary Report: SKM Review of the NGCP Regulatory Submission. Sinclair Knight Merz / Ceurvo Appraisers, March 2, 2010. Table 4-1.


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Total adjustment 3,315.39

3.15 CAPEX in Second Regulatory Period

3.15.1 A comparison of the Regulated Entity’s actual and budget CAPEX over the Second Regulatory Period with the amount allowed in the 2006 Final Determination is presented in Table 3.18 and Figure 3.3. It is apparent that, notwithstanding that the total CAPEX over the regulatory period is anticipated to exceed the allowed CAPEX by 32%, this is due entirely to the increased actual and budgeted expenditure in 2009 and 2010, after NGCP was awarded the franchise.

Table 3.18: Historic CAPEX (PhP million) 2006 2007 2008 2009 2010 Total

Final Determination CAPEX (nominal)1 9,923.40 11,286.90 7,370.80 4,393.00 3,920.20

Final Determination CAPEX (real, 2010) 11,833.23 12,745.41 7,957.23 4,564.50 3,905.31 41,005.68

Actual & Budget CAPEX (nominal)2 6,893.70 8,560.30 7,384.70 8,747.40 18,871.70

Actual & Budget CAPEX (real, 2010) 8,302.43 10,026.06 7,912.59 9,079.80 18,871.70 54,192.58

Note 1: Source: Final Determination, Figure 3.13. Note 2: Source: Revenue Application Annex A, Table 7.3.

Figure 3.3: Historic CAPEX (PhP million, real, 2010)

3.16 OPEX in Second Regulatory Period

3.16.1 A comparison of the Regulated Entity’s actual and budget OPEX over the Second Regulatory Period with the amount allowed in the 2006 Final Determination is presented in Table 3.19 and Figure 3.4. It is apparent that, notwithstanding that the total OPEX over the regulatory period is anticipated to be 8.5% below the allowed OPEX by 32% there is a significant increase in the budgeted OPEX in 2010. When combined with the increase in CAPEX, the total expenditure in 2010 is over 75% higher than in 2009.


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Table 3.19: Historic OPEX (PhP million) 2006 2007 2008 2009 2010 Total

Payroll (nominal)1 2,146.90 2,376.10 2,635.40 2,591.00 2,579.90

Network (nominal)1 2,285.30 2,342.30 2,481.80 2,594.80 2,720.80

Non Network (excl bad debts) (nominal)1 576.10 517.00 534.10 552.30 571.80

Bad Debts (nominal)1 60.60 62.70 63.40 62.90 62.60

Total OPEX, Final Determination (nominal) 5,068.90 5,298.10 5,714.70 5,801.00 5,935.10

Final Determination OPEX (real) 6,044.45 5,982.73 6,169.37 6,027.46 5,912.56 30,136.57

Actual & Budget OPEX (nominal)2 3,466.40 4,006.10 4,922.40 5,726.30 7,483.80

Actual & Budget OPEX (real) 4,174.76 4,692.05 5,274.27 5,943.90 7,483.80 27,568.79 Note 1: Source: Final Determination, Figure 4.9. Note 2: Source: Revenue Application Annex A, Table 7.4.

3.16.2 There are some minor discrepancies in the Revenue Application in respect of the actual and budgeted OPEX for the Second Regulatory Period. In particular the expenditure reported in Table 7.4 of Annex A of the Revenue Application differs from the expenditure shown in Schedule 14, as shown in Table 3.20. These differences are minor and should not have a material impact on the outcome of the analysis undertaken for this Draft Determination.

Table 3.20: Historic OPEX Discrepancies (PhP million, nominal) 2006 2007 2008 2009 2010

Actual & Budget OPEX (nominal)1 3,466.40 4,006.10 4,922.40 5,726.30 7,483.80

Actual & Budget OPEX (nominal)2 3,498.00 4,037.00 4,984.00 5,614.00

Discrepancy 0.9% 0.8% 1.3% (1.9%) Note 1: Source: Revenue Application Annex A, Table 7.4. Note 2: Source: Revenue Application Annex A, Schedule 14 (RAB net of taxes)

Figure 3.4: Historic OPEX (PhP million, real 2010)


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4. TARGET PERFORMANCE IN THE THIRD REGULATORY PERIOD

4.1 Introduction

4.1.1 This chapter discusses the ERC’s views on the outcomes that the Regulated Entity will be expected to deliver over the Third Regulatory Period. It forms a prelude to the following chapter, which addresses in some detail the revenue that the Regulated Entity will need in order to deliver these outcomes.

4.1.2 The chapter considers, in particular, the forecast demand on the network, the levels of service to be provided and the design of the PIS, and the required CAPEX to meet this forecast demand and provide the required levels of service.

4.1.3 The ERC requested its regulatory reset expert, Nel Consulting Ltd (NCL), to review the Revenue Application and supporting evidence provided by the Regulated Entity in all of these areas. The ERC generally accepts the conclusions and recommendations in the NCL Report26 and has used these as the basis for this Draft Determination.

4.2 Demand Forecast

4.2.1 The forecast electricity demand on which the Revenue Application is based on the Department of Energy’s (DOE) high growth load forecast in the Philippines Energy Plan. As this is the upper bound of the range of demand growth rates that the DOE believes to be possible it has, by definition, a low probability of being achieved. Demand growth somewhere in the middle of the range of potential outcomes is much more probable.

4.2.2 The use of such a high demand forecast as the basis for this Draft Determination is problematic for the ERC. Firstly, with such a forecast it is more likely that the situation that arose during the Second Regulatory Period, where transmission rates were determined by the side constraints rather than the required revenue, will be perpetuated. Secondly, for the reasons discussed in Section 3.2, the ERC wants to avoid a situation where all the planning risk associated with the development of the transmission grid is carried by customers. While acknowledging the potential impact on investment if an excessive amount of planning risk is carried by the Regulated Entity, the ERC believes a better balance is necessary if optimal capital investment decisions are to be made.

4.2.3 In determining the appropriate forecast peak demands to use as a basis for determining the required CAPEX for the Third Regulatory Period the ERC has taken due account of the sensitivity of the required CAPEX to the growth in peak demand. The growth in peak demand will also be a factor in converting the MAR into a transmission wheeling rate as it will form the basis for the billing determinant used in this analysis27.

26 The Review of the Historic, Budget and Forecast Expenditure of the National Grid Corporation of the Philippines

for the Third Regulatory Period under Performance Based Regulation, Final. Nel Consulting Ltd, July 12, 2010. 27 The determination of transmission wheeling rates is the subject of a separate rate case that will follow the release of

the Final Determination.


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4.3 ERC Analysis – Demand Forecast

4.3.1 Figure 4.1 shows the historic demand in the Luzon grid and superimposes the various demand forecasts available to the ERC on this historic demand.

Figure 4.1: Luzon Forecast Peak Demand (MW)

Note: SPD = system peak demand.

4.3.2 It is apparent from Figure 4.1 that the DOE’s high forecast is unsupported by historic growth rates and the ERC is not aware of any factor that would indicate a significant upward trend in the historic rate growth in electricity demand. However, Figure 4.1 also shows a relatively small spread between the two forecasts developed from historic growth rates and the NGCP forecast. The ERC is therefore satisfied that, allowing for forecasting uncertainty, the NGCP forecast provides a reasonable basis both for determining the required CAPEX over the Third Regulatory Period.

4.3.3 Figure 4.2 shows the historic demand in the Visayas grid and superimposes the various demand forecasts available to the ERC on this historic demand.

Figure 4.2: Visayas Forecast Peak Demand (MW)


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4.3.4 For the Visayas grid, the load forecasts indicated by both the short and long term historic trend analysis are higher than either the DOE forecast or NGCP’s own forecast. It is not entirely clear why this is the case, but it could be due to uncertainty about the level of suppressed demand that results from the shortage of generation that has existed in the Visayas in the recent past. The ERC notes that that this suppressed demand should be addressed within the Third Regulatory Period. The DOE’s high demand forecast is within the range of forecasts shown in Figure 4.2 and this indicates a realistic chance of this level of load growth being achieved.

4.3.5 Figure 4.3 shows the historic demand on the Mindanao grid and superimposes the various demand forecasts available to the ERC on this historic demand.

Figure 4.3: Mindanao Forecast Demand Analysis

4.3.6 Forecasting future demand on the Mindanao grid is problematic because of the volatility of historic growth trends. If the negative growth in electricity demand that occurred in 2005 and 2008 was to be repeated in 2011 or 2012, then it is possible that the 2015 demand indicated by the 3-year historic forecast, which forms the lower bound of the range of forecasts shown in Figure 4.3, will not be achieved. The DOE high growth forecast would seem to be predicated on the assumption that all generation shortages will be addressed. However, there is insufficient committed generation in the pipeline to indicate that this is likely.

4.3.7 The ERC faces a dilemma in determining the appropriate demand forecast to apply to the Mindanao grid. It recognizes that the use of a low forecast may inhibit investment in the grid to the extent that transmission constraints provide a disincentive to investment in the required generation. On the other hand it is hesitant to require customers to pay for investment that turns out not to be required, either because generation does not materialize or is constructed in a location different from that assumed at this time.

4.3.8 It can be seen from Figure 4.3 that the DOE low load forecast, the NGCP forecast and the 9-year historic demand forecast converge by 2015, possibly


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indicating a level of consensus as to the likely demand on the network by the end of the Third Regulatory Period.

4.4 ERC Preliminary Findings – Demand Forecast

4.4.1 The ERCs Preliminary Findings is that the NGCP demand forecast for Luzon and Mindanao, and the DOE high growth demand forecast for Visayas, will be used as the basis for determining the allowed CAPEX for the Third Regulatory Period. These forecasts are shown in Table 4.1.

Table 4.1: ERC Preliminary Findings – Demand Forecasts (MW) 2011 2012 2013 2014 2015

Luzon 7,364 7,604 7,849 8,097 8,347

Visayas 1,448 1,486 1,545 1,603 1,666

Mindanao 1,381 1,443 1,507 1,577 1,643

Total non-co-incident demand 10,193 10,533 10,901 11,277 11,656

4.4.2 The ERC recognizes the uncertainties inherent in forecasting electricity demand in Mindanao and the risk that a low forecast demand may prevent the network development necessary to encourage the investment in the generation that is needed to fully meet the demand on this grid. There is no indication that this situation is likely to arise. However the ERC will keep the situation under review, and should the situation demand it, consider intervening before the end of the Third Regulatory Period if it considers this to be in the best interests of the electricity consumers in Mindanao.

4.5 Performance Incentive Scheme

4.5.1 The PIS that applied during the Second Regulatory Period is described in Section 3.3. Five performance indicators were used. The actual performance against each indicator was measured separately for each of the three grids giving a total of fifteen (15) separate performance measures. Targets were set for each performance measure based on historic performance against each measure over the period 2000-2004. The scheme placed 3% of the MAR for 2006 (PhP 978.5 million) at risk for each year of the Second Regulatory Period.

4.5.2 As indicated in Section 3.3, the Regulated Entity’s performance over the first four years of the Second Regulatory Period was significantly better than was achieved over the 2000-2004 period, to the extent that the Regulated Entity achieved a total of PhP 1,459.32 million in PIS rewards, more than 37% of the total reward on offer. The ERC is seeking even further improvements in the performance of the grid over the Third Regulatory Period.

4.5.3 In its Revenue Application, the Regulated Entity proposed that the existing 15 performance measures be retained. The ERC considers that an additional three performance indicators should be included in the scheme, in order to address its concern that the Regulated Entity did not have sufficient regard to the impact of its management of the grid on the operation of the Wholesale Electricity Spot Market (WESM) and also the concern that during the Second Regulatory Period the Regulated Entity did not do all it reasonably could to mitigate the impact of its operations on its customers and electricity


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consumers. This latter concern is reflected in the feedback that the ERC has received from the Regulated Entity’s customers.

4.5.4 The new indicators to be included in the PIS for the Third Regulatory Period are:

• Congestion Availability (ConA). This indicator will measure the availability of a subset of the lines and transformers on the Luzon grid. The grid elements included in this indicator have been selected on the basis of the severity of the impact that the loss of the grid element will potentially have on the operation of WESM. Availability will be measured as for the SA indicator.

• Congestion SISI (ConSISI). This indicator will measure SISI for the same subset of lines that is used for the congestion availability indicator. The purpose of introducing the ConSISI measure in addition to ConA is to introduce an indicator that better measures the severity of the impact of unplanned outages of critical lines on the operation of WESM. The ERC proposes that unserved energy be the product of the power flow in the line at the time of the interruption28 (which should be available from the SCADA system) and the duration of the interruption. The peak load should be the coincident peak load on the Luzon grid, as is used for the SISI measure.

• System Interruption Reporting (SIR). This indicator is defined as the average number of days before a planned supply interruption or outage of a grid component occurs that it is reported on NGCP’s web site (such day ending on midnight), as required by Clause C3.2 of the revised OATS Rules29. The measure will be reported separately for each grid.

4.6 ERC Analysis – Performance Incentive Scheme

4.6.1 The ERC considers that there is merit in retaining the indicators used in the Second Regulatory Period provided the targets are adjusted to reflect the improved performance of the network experienced over the first four years of the Second Regulatory Period. Table 4.2 compares the new targets for each of the 15 performance measures with the targets for the Second Regulatory Period.

4.6.2 It can be seen from Table 4.2 that the new targets represent an improvement on current targets for all measures except FLC and VLC on Visayas where the target for the Second Regulatory Period have been retained. The ERC recognizes that, given the geography of the Visayas grid and the current shortage of generation, maintaining voltage and frequency within required limits can be difficult and that the Regulated Entity had some difficulty meeting the targets in the Second Regulatory Period. However, the addition of planned new generation in 2011 may alleviate this problem.

28 This will be measured in MVAr to recognize that the function of a transmission line is to transfer both real and

reactive power. 29 The revised OATS Rules have still to be approved by the ERC. However they have been consulted on and are

expected to be approved by the time the Final Determination is issued.


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Table 4.2: Comparison of New and Current PIS Targets Second Regulatory Period New Targets

NEGATIVE INDICATORS

Luzon

System Interruption Severity Index (SISI) 17.08 9.92

Frequency of Tripping (FOT) 7.88 4.63

Visayas

SISI 272.80 55.75

FOT 7.00 4.14

Mindanao

SISI 61.59 12.83

FOT 9.55 5.52

POSITIVE INDICATORS

Luzon

System Availability (SA) 99.19 99.40

Frequency Limit Compliance (FLC) 99.95 99.97

Voltage Limit Compliance (VLC) 81.06 93.35

Visayas

SA 99.05 99.65

FLC 98.73 98.73

VLC 99.55 99.55

Mindanao

SA 99.08 99.62

FLC 99.84 99.95

VLC 98.42 99.74 Note 1: For a negative indicator a lower number indicates improved reliability. For a positive indicator,

improved reliability is indicated by a higher number.

4.6.3 Insufficient information is available to the ERC at this point to enable the parameters, which include targets, dead bands, collars and caps, for the new congestion measures to be fully defined for inclusion in the PIS. The ERC expects that an analysis of the Regulated Entity’s historic operating records will provide the data required to set a ConA target. If data is not available to set a ConSISI target, then the Regulated Entity will be need to make the necessary measurements over the two year period from 1 September, 2010 to 31 August, 2012 to allow a target to be set. This would allow the parameters of the new performance measure to be confirmed during the 2013 rate setting process and the measure to be introduced on 1 January 2013. In the meantime the weighting allocated to the ConSISI indicator will be added to the ConA indicator.

4.6.4 Data is unlikely to be available to use as a basis for setting the parameters of the new System Interruption Reporting (SIR) indicator. The recommended parameters represent ERC’s view of what is reasonable. The ERC will use these parameters for the first two years of the regulatory period but will review the Regulated Entity’s performance at the time of the 2013 rate review and may introduce revised parameters on January 1, 2013.


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4.7 ERC Preliminary Findings – Performance Incentive Scheme

4.7.1 The PIS for the Third Regulatory Period will include the existing five performance indicators as well as ConSISI, ConA and SIR. All indicators will continue to be measured separately for each grid except ConSISI and ConA, which will be measured for Luzon only.

4.7.2 ConA will be defined in the same manner as the existing SA measure, except that the measure will be confined to the subset of the lines on the Luzon grid shown in Table 4.3. The lines included in this measure have been selected because they are deemed critical to the operation of WESM.

Table 4.3: Network Elements in the ConA and ConSISI Indicators Transmission Lines Power Transformers

San Jose to Tayabas 500 kV San Jose EHV Transformers

Binga to San Manual 230 kV Dasmarinas EHV Transformers

Labrador to Hanjin 230 kV Labrador EHV Transformers

Bauang to Labrador 230 kV San Manuel EHV Transformers

Mexico to Balintawak 230 kV Balintawak EHV Transformers

Pantabangan to Cabanatuan 230 kV Araneta EHV Transformers

Hanjin to Olongapo 230 kV Dolores EHV Transformers

San Jose to Araneta 230 kV Zapote EHV Transformers

Mexico to Hermosa 230 kV Tayabas EHV Transformers

San Manuel to San Jose 500 kV

Balintawak to San Jose 230 kV

Dasmarinas to Tayabas 500 kV

Calauan to Makban 230kV

Kalayaan to Calauan 230kV

Mexico to Hermosa 230kV

4.7.3 ConSISI will be defined in a similar manner to the SISI indicator, except that the energy not served will be measured as the apparent power flow (MVAr) in the line at the time of the interruption. As for the SISI indicator, the peak demand will be the coincident peak demand in the Luzon grid in the measurement year. The measure will be applied to all interruptions (planned and unplanned) of transmission lines included in the ConA subset and will be introduced on January 1, 2013. In 2011 and 2012, the PIS weightings assigned to the ConSISI measure will be applied to the ConA measure.

4.7.4 SIR will be defined as the average number of days before a planned interruption occurs that it is reported on NGCP’s web site (such day ending on midnight), as required by Clause C3.2 of the revised OATS Rules.

4.7.5 The parameters that will apply to each measure for the Third Regulatory Period are shown in Table 4.4.


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Table 4.4: PIS Parameters for the Third Regulatory Period Collar

(Penalty Deadband Cap

(Reward) Low High

Luzon

SISI 22.24 17.96 9.39 5.10

FOT 5.30 4.96 4.29 3.95

SA 99.08 99.19 99.42 99.53

FLC 99.93 99.95 99.99 100.002

VLC 89.60 90.93 93.59 94.92

ConA3 To be determined

ConSISI4 To be determined

SIR3 1 7 14 20

Visayas

SISI 157.40 121.83 50.69 15.12

FOT 9.20 7.45 3.94 2.19

SA 99.44 99.52 99.68 99.75

FLC 96.24 97.49 99.98 1002

VLC 97.52 98.53 100 -1

SIR 1 7 14 20

Mindanao

SISI 34.74 30.74 22.74 18.74

FOT 7.98 6.75 4.28 3.04

SA 99.44 99.53 99.70 99.78

FLC 99.66 99.76 99.96 100.002

VLC 99.59 99.66 99.82 99.89

SIR 1 7 14 20 Note 1: No reward applies as maximum measure (100%) is within the dead band. Note 2: As the maximum possible level of reliability is within one standard deviation of the dead band boundary,

the maximum reward available for this performance indicator is reduced on a pro rata basis. Note 3: Positive indicator (see note to Table 4.2). Note 4: Negative indicator.

4.7.6 The weightings that will apply to each measure for the Third Regulatory Period are shown in Table 4.5.

Table 4.5: Weightings of PIS Measures Indicator

Weightings Grid Weightings


SISI 25% 20% 50% 30%

FOT 25% 34% 33% 33%

SA 20% 34% 33% 33%

FLC 5% 34% 33% 33%

VLC 5% 34% 33% 33%

ConA 5%1 100% - -

ConSISI 5%1 100% - -

SIR 10% 34% 33% 33% Note 1: Prior to January 1, 2013, the weighting applied to the ConA indicator will be 10% and the weighting

applied to the ConSISI indicator will be 0%


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4.7.7 The maximum total reward or penalty under the PIS in any year will be the MAR for 2011, as determined by this Draft Determination. As with the Second Regulatory Period, this maximum reward will be pro-rated across each individual measurement in accordance with the assigned weightings.

4.7.8 Within 21 days from release of this Draft Determination, the Regulated Entity is directed to provide the following information to the ERC:

• historic data showing the actual ConA measure for the subset of network elements specified for each year over the period 2005-2009; and

• its proposed parameters for the ConA measure to be applied during the Second Regulatory Period.

4.7.9 The Regulated Entity is directed to commence formal measurement of the ConSISI and SIR indicators not later than September 1, 2010.

4.7.10 The ERC will set the parameters for the inclusion of the ConSISI indicator into the PIS during the fourth quarter of 2012. This will be done as part of the rate setting process for 2013. The parameters will be based on the measured performance over the two year period from September 1, 2010 – August 31, 2012.

4.7.11 During the fourth quarter of 2012, the ERC will review the Regulated Entity’s measured performance against the SIR indicator. It may reset the parameters to apply from January 1, 2013 based on the actual performance over the two year period September 1, 2010 – August 31, 2012.

4.8 Forecast CAPEX

4.8.1 The Regulated Entity’s forecast CAPEX for the Third Regulatory Period as presented in its Revenue Application is shown in Table 4.6. A comparison of this forecast CAPEX with the actual and budgeted CAPEX in the Second Regulatory Period as shown in Table 3.18, with all expenditures converted to real 2010 PhP, is shown in Figure 4.1. The Regulated Entity’s forecast CAPEX in the Third Regulatory Period is 49% higher than the actual and budgeted expenditure in the Second Regulatory Period, due to the high forecast CAPEX in the first three years of the period. It is also noted that budgeted CAPEX in 2010 exceeds what was spent in 2009 by more than 100%.


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Table 4.6: Forecast CAPEX (PhP million, real 2010) 2011 2012 2013 2014 2015 Total

Luzon 9,857.85 8,070.99 6,265.52 2,059.38 1,382.86 27,636.60

Mindanao 5,153.02 2,029.19 1,372.28 809.51 666.30 10,030.30

Visayas 4,333.13 2,695.39 1,753.58 1,086.25 188.65 10,057.00

ROW under court litigation 175.75 212.13 228.31 219.53 221.95 1,057.67

Capitalized Overhead Engineering 724.74 706.40 721.65 729.37 739.17 3,621.33

Capitalized Overhead Administration 23.44 23.87 24.14 24.35 24.64 120.44

Operations & Maintenance CAPEX 4,901.31 2,412.87 1,619.45 1,830.57 1,096.56 11,860.76

Head Office 551.74 342.38 168.16 72.92 59.95 1,195.15

System Operations 3,338.14 1,567.72 1,522.02 793.15 657.28 7,878.31

Metering Services 130.85 108.84 102.13 99.79 81.77 523.38

TransCo 1,466.92 1,551.55 1,423.62 1,239.31 1,116.73 6,798.13

Total 30,656.89 19,721.33 15,200.86 8,964.13 6,235.86 80,779.07

Figure 4.4: Comparison of Historic and Forecast CAPEX (PhP million, real 2010)

4.9 ERC Analysis – CAPEX for RAB Assets

4.9.1 A significant driver for the recommended reduction in CAPEX is the deferral of projects due to the reduction in the load forecast for Luzon and Mindanao. The ERC notes the volatility of the historic demand in Mindanao30 and does not want a situation to develop whereby necessary investment in generation does not occur because of transmission constraints. As far as it is aware, this

30 See Figure 5 of the NCL report.


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is not the present situation and the current shortage of investment in generation is due to other reasons. Given this, the ERC believes that it would be potentially inefficient to accelerate transmission grid development to supply demand that cannot be met by available generation. Such a strategy not only requires customers to pay more in order to fund the construction of transmission infrastructure before it can be effectively utilized but also implies a risk of sub-optimal development by constructing infrastructure to support a generation development scenario that does not materialize. It would be more efficient to adopt a “wait and see” approach and to ask customers to fund the augmentation of the grid in a way that is known will support planned new generation investment.

4.9.2 The ERC urges the Regulated Entity to monitor the situation on an ongoing basis and to actively encourage investment in efficient new generation. Should it become apparent that the forecast CAPEX allowed in this Draft Determination is inadequate to support planned investment in efficient new generation the Regulated Entity, with the support of the proponents of the generation investment, should file for the early approval of any additional CAPEX that might be needed to allow the proposed generation project to proceed. The ERC will treat any such application on its merits.

4.9.3 Another significant unknown is the cost of settling ROW claims as they relate to both existing and new projects. It is not possible to separate ROW costs from land purchases on the basis of an analysis of the information provided in the Revenue Application, as the Regulated Entity has not correctly attributed costs for transmission line ROW acquisition – for example NGCP costs attributed to ROW under court litigation have all been classified as falling within the line item land owned but used for substations when it is reasonable to assume that the bulk of these costs are likely to be paid to landowners affected by transmission line construction.

4.9.4 The Regulated Entity’s total forecast CAPEX in the Third Regulatory Period for land purchases and the settling of ROW claims is shown in Table 4.7.

Table 4.7: Forecast CAPEX for Land Purchase and ROW (PhP million, real 2010)

2011 2012 2013 2014 2015 Total

NGCP

Transmission lines 1,036.96 1,137.62 680.80 145.93 48.30 3,049.61

Substations 232.37 225.59 229.18 219.84 222.27 1,129.25

Communication plant - - - - - -

System operations - - - - - -

Administration 20.00 19.18 18.44 - - 57.61

Total NGCP 1,289.33 1,382.39 928.42 365.77 270.57 4,236.47

TransCo 1,466.92 1,551.55 1,423.62 1,239.31 1,116.73 6,798.13

Total NGCP and TransCo 2,756.25 2,933.94 2,352.04 1,605.08 1,387.29 11,034.61

4.9.5 It can be seen from Table 4.2 that total forecast expenditure on land purchase and ROW acquisition exceeds PhP 11 billion and represents 13.7% of the Regulated Entity’s total forecast CAPEX over the Third Regulatory Period.


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However, over the first three years of the Second Regulatory Period, for which audited actual expenditure is available, land and ROW acquisition costs comprised only 7.8% of actual CAPEX.

4.9.6 The difficulty for the ERC is that ROW costs clearly form a very significant component of its total forecast CAPEX but, because of the nature of these costs, it is very difficult to assess whether or not the forecast is reasonable. This problem is not unique to the Philippines – it is also encountered in jurisdictions such as New Zealand and Australia. As a general rule, forecasts tend to underestimate the magnitude of ROW settlement costs but bring forward the actual timing, due to the extended time often taken to resolve the legal issues. If this holds true over the Third Regulatory Period, then it is possible that some of the ROW settlement CAPEX forecast to occur during the Third Regulatory Period may not occur until the Fourth Regulatory Period. The ERC wants to avoid a situation where such costs are captured as an efficiency gain during the Third Regulatory Period (because the expenditure does not occur) and are then included in the Fourth Regulatory Period CAPEX forecast. In such an event customers could pay twice and the Regulated Entity could receive a windfall gain.

4.9.7 Due to the fact that ROW settlement costs form a significant component of the CAPEX requirement and the high level uncertainty in forecasting these costs, the ERC has decided these will be settled on an ex post basis. The Regulated Entity will be reimbursed only for the efficient costs actually incurred in settling ROW claims, where the amount to be paid will be determined by a prudency review of actual ROW settlement and land acquisition costs that will form part of each reset. This prudency review will involve an examination of the actual costs of settling claims in the current regulatory period in order to establish that the settlement costs are efficient and that the Regulated Entity has taken appropriate steps to minimize these costs to the extent allowed by law. Prudent costs will be reimbursed through a carryover in the subsequent regulatory period, together with a return on the actual costs equivalent to the current WACC.

4.10 ERC Preliminary Findings - CAPEX for RAB Assets

4.10.1 ERC’s preliminary findings on the Regulated Entity’s CAPEX on RAB assets for the Third Regulatory Period is shown in Table 4.8. It should be noted that the ERC’s approved CAPEX excludes all land related capital costs, including land purchase costs and also excludes VAT.

Table 4.8: ERC Approved CAPEX – RAB Assets (PhP million, real 2010)

2011 2012 2013 2014 2015 Total

Approved CAPEX (including VAT) 13,189.60 12,626.14 9,319.06 5,884.02 3,196.00 44,214.82

Estimated VAT 508.64 422.95 316.47 211.67 119.14 1,578.87

ERC approved CAPEX 12,680.96 12,203.19 9,002.59 5,672.35 3,076.86 42,635.94

4.10.2 The total ERC approved CAPEX for the Third Regulatory Period is 4% higher in real terms than the approved CAPEX for the Second Regulatory Period in


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the 2006 Final Determination. However, this CAPEX does not include ROW and land acquisition costs. Once these costs are factored in, the ERC’s preliminary findings represents a significant increase in real terms over the allowance in the 2006 Final Determination.

4.10.3 A comparison of the ERC approved CAPEX for RAB assets with the Regulated Entity’s actual and budgeted, and forecast CAPEX, both as presented in the Revenue Application, is provided in Figure 4.5.

Figure 4.5: Comparison of ERC Approved CAPEX on RAB Assets with Regulated Entity’s Actual and Forecast CAPEX (PhP million, real 2010)

4.11 ERC Analysis – CAPEX for Residual Subtransmission Assets

4.11.1 In accordance with the provisions of Article V, Section V of ERC Resolution No 1, Series of 2009 (and as further clarified by Clause 2 of Resolution No 18, Series of 2009), residual subtransmission assets that have not been sold by December 31, 2010 are to be retained by the Regulated Entity and should be included in the RAB as at the beginning of the Third Regulatory Period. It follows that forecast CAPEX on residual subtransmission assets during the Third Regulatory Period should be included in the CAPEX forecast used to determine the revenue requirement for the provision of regulated transmission services.

4.11.2 The Regulated Entity’s forecast CAPEX for residual subtransmission assets is presented in Schedule 12 of Annex A of the Revenue Application and is shown in Table 4.9. This forecast includes VAT which is estimated to comprise 3.6% of VAT inclusive of CAPEX.

4.11.3 The total forecast CAPEX (excluding VAT) over the Third Regulatory Period amounts to only 4.1% of the ERC’s preliminary findings on the allowed CAPEX for other RAB assets. Any adjustments resulting from an efficiency review of this CAPEX would affect only a portion of this and, in the view of ERC, would be unlikely to have a material impact on the total CAPEX spent,


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particularly as there are no land related costs included in the forecast. The ERC has therefore decided to accept the Regulated Entity’s CAPEX forecast for residual subtransmission assets without further adjustment.

Table 4.9: CAPEX for Residual Subtransmission Assets (PhP million)

2011 2012 2013 2014 2015 Total

Regulated Entity forecast (nominal)1 549.44 393.97 376.49 374.08 314.60

Regulated Entity forecast (real) 526.79 363.20 333.74 318.85 255.14 1,797.70

Estimated VAT (real) 18.96 13.08 12.01 11.48 9.18 64.72

Regulated Entity forecast excl. VAT (real) 507.82 350.12 321.72 307.37 245.95 1,732.99

Note 1: Source: Revenue Application, Annex A, Schedule 14.

4.12 ERC Preliminary Findings – Forecast CAPEX

4.12.1 ERC’s preliminary findings on the Regulated Entity’s allowed CAPEX for the provision of regulated transmission services over the Third Regulatory Period is presented in Table 4.10. A comparison with the Regulated Entity’s actual and budgeted CAPEX over the Second Regulatory Period and its Revenue Application Forecast for the Third Regulatory Period is shown in Figure 4.6. In this figure the Regulated Entity’s forecast includes forecast CAPEX for residual subtransmission assets as well as VAT and land related CAPEX. As discussed above, VAT and land related CAPEX are not included in the ERC approved costs. A breakdown of the approved CAPEX into the ERC’s standard expenditure categories as used in the regulatory revenue model is presented in Appendix B.

Table 4.10: ERC Approved Forecast CAPEX – All Assets (PhP million, real 2010)

2011 2012 2013 2014 2015 Total

ERC approved CAPEX for RAB assets 12,680.96 12,203.19 9,002.59 5,672.35 3,076.85 42,635.94

ERC approved CAPEX for residual subtransmision assets 507.82 350.12 321.72 307.37 245.95 1,732.99

Total ERC approved CAPEX 13,188.78 12,553.31 9,324.31 5,979.72 3,322.80 44,368.93


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Figure 4.6: Comparison of ERC Approved CAPEX on RAB Assets with NGCP Actual, Budget and Forecast CAPEX (PhP million, real 2010)


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5. REVENUE REQUIREMENT IN THIRD REGULATORY PERIOD

5.1 Introduction

5.1.1 This chapter examines the revenue that the Regulated Entity will require during the Third Regulatory Period to deliver the outcomes described in Chapter 4. In determining the MAR, the ERC has relied on the report31 of its regulatory reset expert, NCL, whose scope of work included recommending the required OPEX for the Third Regulatory Period and the net efficiency adjustment (NEA) to be applied. The ERC generally accepts the conclusions and recommendations of NCL in respect of these areas, and has used these as the basis of this Draft Determination.

5.2 Forecast OPEX

5.2.1 The Regulated Entity’s forecast OPEX as presented in its Revenue Application is shown in Table 5.1. A comparison of this forecast OPEX with the actual and budgeted OPEX, as shown in Table 3.19, with all expenditures converted to real 2010 PhP, is shown in Figure 5.1. This comparison indicates that the Regulated Entity is forecasting total OPEX to increase by around 30% in real terms in the Third Regulatory Period. Further, unlike the allowed OPEX for the Second Regulatory Period, the forecast OPEX in the Third Regulatory Period is relatively constant over the period, notwithstanding the fact that actual OPEX during the Second Regulatory Period increased progressively on an annual basis.

Table 5.1: Forecast OPEX (PhP million) 2011 2012 2013 2014 2015 Total

Forecast OPEX (nominal)1 Payroll 3,454.00 3,709.00 3,927.00 4,131.00 4,347.00 -

Network related 2,158.00 2,237.00 2,315.00 2,867.00 2,520.00 -

Non-network related 2,110.00 1,726.00 1,634.00 1,679.00 1,741.00 -

Total 7,722.00 7,672.00 7,876.00 8,677.00 8,608.00 -

Forecast OPEX (real, 2010) 7,403.64 7,072.79 6,981.60 7,395.80 6,980.96 35,834.80

Note 1 Source: Revenue Application, Annex A, Schedule 13 (Transmission OPEX without taxes)

31 Supra note 27.


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Figure 5.1: Comparison of Historic and Forecast OPEX (PhP million, real 2010)

5.3 ERC Analysis – Forecast OPEX for RAB Assets

5.3.1 It was apparent from the evidence given by NGCP witnesses at the evidentiary hearings that, in preparing the OPEX forecast presented in the Revenue Application, individual managers were asked to prepare budgets for their areas of responsibility and these budgets were then aggregated to provide the final forecast. While there was some evidence of a process of management review and moderation, no evidence was presented on the criteria used for this review and moderation process. Furthermore, no evidence was presented on the need for the 30% real increase in OPEX given that, as discussed in Section 3.3, the actual expenditure during the Second Regulatory Period was sufficient to deliver significant improvements in the quality of the service provided to customers.

5.3.2 The ERC considers that a top-down forecasting approach reflects the reality faced by firms providing a service in a competitive environment better than the bottom-up approach used by the Regulated Entity. In a competitive environment, the prices charged by other market participants for similar products or services provide an upper limit to the expenditures that a firm can sustain. Businesses are forced to keep their total expenditures within this limit, to prioritize initiatives that complete for the available funds and to defer or eliminate low priority expenditure. The forecasting approach used by the Regulated Entity appears to lack a defined and transparent upper bound and, as a result, there was little evidence of a rigorous process for prioritizing proposed programs or identifying and eliminating wasteful expenditure.

5.3.3 The ERC further notes that the Regulated Entity has provided no evidence as to why the 2009 salary increases, which were granted as a result of the Ernst and Young study, were needed. Determinations made by the ERC for investor owned DUs operating under PBR have not allowed labor cost increases in excess of CPI, unless compelling evidence is provided that such increases are necessary to ensure the sustainability of the entity being regulated. No such evidence has been provided in support of this Revenue Application. One of the main objectives of EPIRA is to control and where possible reduce


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electricity prices and RBR is designed to support this objective. However, it is difficult to see how real price reductions will be achieved unless the escalating real cost of labor in the industry is aggressively addressed. The ERC notes that privatization of electricity utilities in other jurisdictions has generally resulted in a real reduction in labor costs, usually though increasing labor productivity.

5.3.4 The forecast OPEX in the Revenue Application includes VAT as this will need to be recovered from the transmission wheeling rate over the Third Regulatory Period. The treatment of VAT by the Regulated Entity during the Third Regulatory Period is discussed in Section 5.22. As explained in that section, VAT is treated as a separate cost in the analysis for this Draft Determination and it will therefore need to be excluded from the approved OPEX.

5.4 ERC Analysis – TransCo OPEX

5.4.1 The Revenue Application includes the OPEX forecast to be incurred by TransCo over the Third Regulatory Period32. This expenditure includes:

• expenses incurred in the sale of subtransmission assets;

• expenses incurred in processing ROW claims33; and

• one-off recoveries of supervision and permit fees in respect of the Regulated Entity’s approved CAPEX for the Third Regulatory Period and also in respect of its force majeure event (FME) claim.

5.4.2 In accordance with ERC Resolution No 1, Series of 2009, the sale of subtransmission assets will not occur during the Third Regulatory Period and at the evidentiary hearings TransCo testified that this cost was for the management of the sale of connection assets to qualified distribution utilities. These costs are not related to RAB assets and should therefore be recovered from the proceeds of the connection asset sales.

5.4.3 The management of ROW claims is an ongoing expenditure that was incurred by TransCo in its role as transmission service provider before the effectivity of RA 9511. The fact that under the concession agreement some of these costs are to be incurred by TransCo and some by NGCP is not directly relevant to the ERC’s consideration of the Revenue Application. The ERC’s approved OPEX for RAB assets has been derived using a top-down forecasting model that escalates an efficient base cost, which was based on the actual OPEX incurred over the period 2006-2008 prior to the transfer of the concession to NGCP. The approved RAB asset OPEX therefore includes all ROW management costs that will be incurred by both TransCo and NGCP and no separate adjustment is required to include TransCo’s forecast expenditure.

5.4.4 The Revenue Application does not explicitly discuss the basis for including the one off recoveries of supervision and permit fees. However it appears from a review of the ERC Order dated October 9, 2008 in respect to ERC Case

32 This OPEX is detailed in Schedule 19 of Annex A of the Revenue Application. 33 This expenditure relates only to the processing of ROW claims. The expenditure incurred in settling claims is

treated as CAPEX.


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No. 2005-041-RC that the National Power Corporation34 (NPC) was not subject to these fees and, in preparing its OPEX forecast for the Second Regulatory Period, TransCo assumed that it would also be covered by this exemption. Hence, these fees were not provided for in the Second Regulatory Period OPEX forecast. On this basis, recovery of these costs, which the ERC imposed on TransCo in its October 2009 Order, is reasonable. However the more correct way of dealing with this issue is to include these costs in the adjusted OPEX forecast prepared as the basis for calculating the operations and maintenance efficiency adjustment (OEA). Hence these costs are not included in the OPEX allowed by this Draft Determination but have been allowed for in determining the OEA in Section 5.29.

5.5 ERC Analysis – OPEX for Residual Subtransmission Assets

5.5.1 An issue that does not appear to have been addressed in the Revenue Application is the forecast cost of operating residual subtransmission assets during the Third Regulatory Period. In accordance with Clause B19.7 of the draft OATS Rules, which await promulgation of the ERC, this cost will need to be recovered from the regulated transmission wheeling rate after January 1, 2011. However, these costs have not been provided for in the regulatory model submitted with the revenue application.

5.5.2 NGCP’s forecast OPEX for residual subtransmission assets, excluding taxes, is provided in Schedule 13 of the Revenue Application. However, this OPEX does not include the efficiency adjustments that the ERC has applied to the RAB asset OPEX forecast in the Revenue Application, and insufficient information has been provided to allow the ERC to accurately assess the efficiency and reasonableness of this forecast. It is likely that a downward adjustment will be necessary if only to reflect the impact of lower labor costs. For the purposes of this Draft Determination, the ERC has therefore reduced the Revenue Application residual subtransmission asset OPEX forecast by 17.48%, which is the same reduction that was applied to the RAB OPEX when averaged across the whole of the regulatory period. It should be noted that this reduction also includes the removal of VAT from the Revenue Application forecast. This analysis is shown in Table 5.2.

Table 5.2: Residual Subtransmission OPEX Forecast (PhP million) 2011 2012 2013 2014 2015 Total

Revenue Application forecast without taxes (nominal)1 372.00 392.00 410.00 481.00 450.00

Revenue Application forecast without taxes (real, 2010) 356.66 361.38 363.44 409.98 364.94 1,856.41

ERC Forecast without taxes (real, 2010) 294.31 298.20 299.90 338.30 301.14 1,531.86

Note 1: Source: Revenue Application, Annex A, Schedule 13.

5.6 ERC Preliminary Findings – Forecast OPEX

5.6.1 In determining the Regulated Entity’s allowed OPEX for the Third Regulatory Period, the ERC has decided that:

34 TransCo was formed as a separate entity to manage the transmission assets of NPC.


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• TransCo’s OPEX for the management of the sale of connection assets is not related to RAB assets and should not be included in the forecast;

• TransCo’s OPEX for the processing of ROW claims for existing projects is a legitimate expense but is already included in the approved OPEX;

• The recovery of supervision and permit fees related to CAPEX during the Second Regulatory Period is reasonable but should be accounted for in the adjustment of the OPEX forecast for determining the OEA.

5.6.2 ERC’s preliminary findings on the forecast OPEX for the Third Regulatory Period, expressed in real, 2010 PhP and excluding VAT, is shown in Table 5.3. A comparison of this allowed forecast OPEX with the Regulated Entity’s historic and forecast expenditure is shown in Figure 5.2.

Table 5.3: ERC Allowed OPEX (PhP million, real 2010) 2011 2012 2013 2014 2015 Total

RAB Assets

Revenue Application Forecast 7,403.64 7,072.79 6,981.60 7,395.80 6,980.96 35,834.80

ERC Preliminary Findings (excluding VAT) 5,406.00 5,836.00 5,824.00 6,504.00 6,000.00 29,570.00

Residual Subtransmission Assets

Revenue Application Forecast 356.66 361.38 363.44 409.98 364.94 1,856.41

ERC Preliminary Findings (excluding VAT) 294.31 298.20 299.90 338.30 301.14 1,531.86

Total

NGCP Forecast 7,760.31 7,434.18 7,345.04 7,805.78 7,345.90 37,691.20

ERC Preliminary Findings (excluding VAT) 5,700.31 6,134.20 6,123.90 6,842.30 6,301.14 31,101.86

Figure 5.2: Comparison of ERC Allowed OPEX with Actual OPEX and Revenue Application Forecast (PhP million, real 2010)


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5.7 Regulatory Asset Base

5.7.1 The value of the RAB over the Third Regulatory Period forms the basis for two of the building blocks used to calculate the MAR. Specifically:

• the Regulated Entity can earn a return on its investment in the RAB. This is equivalent to the interest an individual receives on money put into the bank or the dividend an investor receives on shares in a corporation. This component of the MAR is often referred to as a return on assets.

• the investment that the Regulated Entity makes in an asset is returned to the investor progressively over the economic life of the asset. This is analogous to a lender repaying the principal amount of a loan in installments over the period of the loan. This component of the MAR is sometimes referred to as a return of assets and is commonly called depreciation by accountants. The amount of depreciation returned to the investor in any one year depends on the economic life of the asset. This in turn depends on the type of asset, since the economic lives of the different asset types used in the provision of regulated transmission services differ.

5.7.2 In each year of the Third Regulatory Period the value of the RAB will increase by the amount of CAPEX incurred and reduced by the amount of depreciation returned to the Regulated Entity as the investor in the RAB. The calculation of the value of the RAB at the end of each year of the regulatory period is one of the analyses undertaken by the ERC’s regulatory revenue model.

5.8 Initial Asset Valuation

5.8.1 A key input to the analysis within the ERC regulatory model to determine the return on assets and the return of assets is the value of the RAB at the beginning of the Third Regulatory Period, i.e. January 1, 2011. Normal


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practice is to undertake an asset valuation after the valuation date, when it is possible to know with certainty the assets that were installed as at the valuation date. However this is not possible for a PBR reset as the MAR must be determined in advance. Hence Section 5.6 of the RTWR provides for the regulatory asset valuation to be undertaken as of a date prior to the beginning of the Third Regulatory Period. This valuation is rolled forward, in accordance with Section 5.7 of the RTWR, to the beginning of the Third Regulatory Period, on the basis of the expected CAPEX between the initial valuation date and the beginning of the subsequent regulatory period.

5.8.2 The ERC engaged SKM35 to value the asset base as of December 31, 2008 and SKM submitted its Valuation Report36 on November 23, 2009, providing an optimized depreciated replacement cost (ODRC) valuation of the RAB asset base of PhP 147,033.41 million. The ODRC valuation is the value on which the Regulated entity is entitled to earn a return. This SKM valuation included only commissioned assets.

5.8.3 In Section 11 of Annex A of the Revenue Application, the Regulated Entity proposed a number of adjustments to this asset valuation for a number of reasons including:

• assets that were not included in the valuation but should have been included;

• optimization37 that was not acceptable to the Regulated Entity;

• assets found between the last regulatory period and the present regulatory period;

• assets for exclusion (for example because they had different ownership status than assumed by the valuer); and

• zeroing errors found in formulae used by the valuer, which affected the valuation of system control and data acquisition (SCADA) assets.

5.8.4 In addition to the above adjustments, which for the most part relate directly to the assets that make up the RAB, the Regulated Entity made two additional adjustments to the SKM valuation. These included:

• the addition of the value of construction work in progress (CWIP); and

• an adjustment to the construction work in progress factor (CWIP factor)38 assumed in the SKM valuation, driven primarily by the use of a different value for the WACC. The use of the CWIP factor is discussed in Section 5.10.

35 SKM engaged Cuervo Associates as a subcontractor responsible for the valuation of land

and non-network assets. 36 Valuation of the Regulatory Asset Base of the National Grid Corporation of the Philippines,

Valuation Report, Final, Sinclair Knight Merz, November 23, 2009. 37 Optimization is a component of the asset valuation process that involves a downward adjustment to the value of the

asset base to reduce the value of assets with excess capacity or that are not required to supply the forecast load. 38 CWIP should not be confused with CWIP factor. CWIP relates to physical assets that have still to be commissioned

whereas the CWIP factor refers to a financial multiplier applied to the value of commissioned assets in order to reimburse the cost of financing these assets while they are under construction.


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5.8.5 As a result of the adjustments discussed in the previous two paragraphs increased the Revenue Application assumed an initial asset valuation of PhP 160,936.30 million, 10.2% higher than the ODRC valuation in the SKM report. These adjustments are shown in Table 5.4.

Table 5.4: Revenue Application Adjustments to SKM’s Initial RAB Asset Valuation (PhP million, nominal)

SKM initial valuation of commissioned RAB assets (as of December 31, 2008)2 146,049.70

Asset base related adjustments (Paragraph 5.7.3) 6,003.50

Adjustments to the CWIP factor 901.50

CWIP 7,981.50

Revenue Application revised RAB asset valuation (as of December 31, 2008) 160, 936.30 Note 1. Source: Revenue Application, Annex A, Table 11.18. Note2: This value is different from the value given in paragraph 5.7.2, which was taken from the body of the

Valuation Report. Section 11.2.2 of the Revenue Application indicates that these differences are due to inconsistencies between the Valuation Report and the supporting spreadsheets provided to NGCP. Table 11.18 of Annex A of the Revenue Application uses the lower spreadsheet value.

5.9 ERC Analysis – Asset Base Related Adjustments

5.9.1 The ERC was not able to take a position on the asset base related adjustments proposed in the Revenue Application as these in the main related to the accuracy of the asset register used as a basis for the valuation. It therefore requested SKM to review its asset register in consultation with the Regulated Entity and to correct any errors. Given the size of the register, some errors were to be expected and reconciliation of the valuation asset register with the asset owner’s records is a normal part of the valuation process. Time constraints had prevented this process from being fully completed before the Valuation Report was needed as an input to the Revenue Application.

5.9.2 On completion of this review process SKM submitted a Supplementary Valuation Report39 that revised its initial valuation of RAB assets to PhP 151,188.47 million. The ERC accepts the initial asset values in SKM’s Supplementary Valuation Report, subject to the removal of the CWIP factor as discussed in Section 5.10, and has used these adjusted values in its analysis as the basis for this Draft Determination.

5.10 ERC Analysis – CWIP Factor

5.10.1 Clause 4.6.8(b) of the RTWR requires that only assets that, except in the case of spares, are in service (i.e. have been commissioned and are providing a service) (ERC emphasis) should be included in the RAB. Notwithstanding this, the Regulated Entity has included CWIP in its initial asset value (as shown in Table 5.4) and, furthermore, states that the RTWR is silent on whether CWIP should be included40 in the asset valuation.

5.10.2 In explaining its reasons for including CWIP in the initial asset valuation, the Regulated entity notes that the SKM valuation is of commissioned assets only and submits that the value of CWIP must be added to result in an appropriate

39 Valuation of the Regulatory Asset Base of the National Grid Corporation of the Philippines,

Valuation Report, Supplementary Report, Sinclair Knight Merz, March 2, 2010. 40 Table 11.18 of Annex A of the Revenue Application


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value of the RAB. It argues that this is because in rolling forward the RAB from December 2008 (to December 2010) CAPEX is added to the RAB as spent, not as commissioned, and therefore the value of CWIP would be ignored and lost from the valuation base unless an explicit adjustment is made. It then states that the value of CWIP should be escalated by a CWIP factor to compensate for the time value of money that would be incurred in constructing replacement assets41.

5.10.3 Clause 4.6.10 of the RTWR states that the CWIP factor … is intended to compensate for the investment cost (i.e. the time value of money) calculated using a typical spend profile for assets of the relevant type (at the weighted average cost of capital determined by the ERC …) over the typical period from the commencement of the construction of such assets to the commissioning of those assets (excluding any periods of unjustifiable delay).

5.10.4 As noted in paragraph 5.10.1, while the RTWR allows a CWIP factor to be applied to the initial asset valuation, it explicitly states that CWIP should not also be included in the valuation. This is the intended outcome, which follows from the economic purpose of the CWIP factor. Some transmission assets take a long time to construct, to the extent that the cost of financing the construction of the asset before it is put into service is material. The ERC accepts that it is reasonable for a regulated entity to recover this financing cost. If CWIP is included in the asset base, then the financing cost is recovered through the return received by the investor before the assets are commissioned. If, however, assets are only included in the asset base after commissioning, then this return is foregone and the financing cost must be capitalized in order for it to be recovered. This is done through the CWIP factor. The CWIP factor is calculated by estimating the cash requirements during the construction period for the typical project and calculating the cost of providing this cash, assuming that the WACC represents the cost of providing cash to the business. It thus represents a reasonable estimate of the cost of financing a typical project.

5.10.5 This view that a CWIP factor should not be applied if CWIP is included in the RAB is supported by the New Zealand Commerce Commission, which has stated:

In its previous papers the Commission has also stated that it considers that there are two potential accounting treatments for Works under Construction (WUC):

• WUC can be added to the RAB on the basis of the costs incurred on a project as at regulatory year-end. Under this treatment there is no need to include finance during construction (FDC) costs in the capital cost of the project since a business is able to earn a return on capital invested in un-commissioned works.

• Assets can only be added into the RAB at the time they are commissioned. In this event financing costs are a legitimate project cost and should be included in the capital cost of the project. This can either through an additional allowance in the

41 Revenue Application, Annex A, Section 11.4.


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standard replacement cost or an allowance can be added into the RAB42.

5.10.6 The RTWR would be fully consistent with the use of the CWIP factor as the method for recovering the cost of financing projects under construction if it had been clear that the term Capexj,t-1 described in Clause 4.6.10(b) referred to the total CAPEX spent on assets commissioned during the year t-1 (irrespective of the year in which the expenditure was actually incurred). This was the intent of the clause. In the Revenue Application, the Regulated Entity has interpreted this clause as requiring actual and forecast CAPEX to be presented “as spent” rather than “as commissioned”.

5.10.7 In rolling forward the asset base to December 31, 2010 the Regulated Entity has included CWIP and added a CWIP factor to actual construction costs. The ERC does not accept that this roll forward approach is valid as it implies a double recovery of the cost of financing CWIP. Given the fact that the Regulated Entity’s CAPEX forecast is presented “as spent” rather than “as commissioned”, the ERC has decided to include CWIP in the RAB and not apply a CWIP factor to the initial asset valuation or to new CAPEX. It follows that CAPEX will continue to be included in the RAB “as spent” rather than as commissioned.

5.10.8 The decision means that it is unnecessary to review the CWIP factor calculated by PwC FA. Notwithstanding this, it appears that the WACC used in calculating the CWIP factor used in the Revenue Application was the WACC proposed for the Third Regulatory Period. The ERC does not understand the basis for this, given that the initial roll forward was for the final two years of the Second Regulatory Period. Had it been necessary to review the CWIP factor for the purposes of these preliminary findings, the ERC would have replaced this WACC with the approved WACC for the Second Regulatory Period, in addition to any other adjustments that it might have considered necessary.

5.11 ERC Analysis – Initial Asset Valuation

5.11.1 The first step in the analysis was to exclude the CWIP factor from SKM’s revised valuation and add in the CWIP. ERC has accepted the CWIP value provided in Table 11.15 of Annex A of the Revenue Application except that the component “Found and Other Residuals” has been excluded. No explanation has been provided for this component and it is not clear whether these assets were included in the adjusted SKM valuation as a result of the adjustment that occurred subsequent to the completion of the asset valuation. This adjustment to SKM’s initial asset valuation is shown in Table 5.5.

42 Methodology for Rolling Forward the Regulatory Asset Base for System Fixed Assets, New Zealand Commerce

Commission, April 13, 2006, paragraph 142, p36. This paper is available for downloading from the New Zealand Commerce Commissions web site, http://www.comcom.govt.nz/valuation-of-the-regulatory-asset-base/


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Table 5.5: ERC Adjustments to SKM’s Initial RAB Asset Valuation (PhP million, nominal)

SKM Valuation (Dec 08)

ERC Revised Valuation (Dec 08)

Commissioned Assets

Transmission lines 90,936.55 82,896.51

Substations 52,072,81 47,835.32

Communications plant 3,577.65 3,577.65

System operations 1,910.13 1,910.13

Non-network assets 2,691.33 2,691.33

Subtotal 151,188.47 138,910.94

CWIP

Transmission lines 2,540.34

Substations 3,210.30

Communications plant and metering 329.45

System operations 116.99

Non-network assets 73.65

Subtotal 6,270.94

TOTAL 151,188.47 145,181.88

5.11.2 It would seem that the Regulated Entity still has some concerns in respect of the accuracy of the SKM asset valuation and presented further proposed adjustments in Figure 2 of its Supplemental Report43. The impact of these adjustments is shown in Table 5.6.

Table 5.6: Regulated Entity Changes to SKM’s Initial Asset Valuation (PhP million, December 08)

SKM Valuation1

Revised Valuation (Supplemental

Report

Impact

RAB Assets 151,188.50 150,819.30 (0.2%)

Residual Subtransmission Assets 13,351.60 12,469.90 (6.6%)

Connection Assets 9,773.90 11,038.20 12.9%

Total 174,314.00 174,327.40 Note 1. Includes SKM’s CWIP factor.

5.11.3 According to the Regulated Entity44, the adjustments shown in Table 5.6 arise from a reclassification of asset categories, although the reason for the minor change in asset values apparent from Table 5.5 is not clear. Overall however, the net effect is a reclassification of RAB and residual subtransmission assets (which are the subject of this Draft Determination) to connection assets. In

43 Submission to the Energy Regulatory Commission on the Regulatory Reset Requirements for

the Third Regulatory Period (2011-2015) under the Rules for Setting Transmission Wheeling Rates foe 2003 to around 2027 – A Supplemental Report, National Grid Corporation of the Philippines, (NGCP), April 30 2010.

44 Ibid, paragraph 15.


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total the reduction in the value of the RAB and residual subtransmission assets is only 0.8%, which is well within the expected accuracy of the valuation and any reasonable materiality threshold. The ERC has therefore decided not to reflect these proposed changes in this Draft Determination.

5.11.4 Notwithstanding this, the impact of these reclassifications on the value of connection assets is material and this is of concern to the ERC as it may have an impact on the way connection charges are set under the OATS Rules. For this reason the issue may need to be revisited in the Final Determination. The ERC gave the Regulated Entity and SKM ample opportunity to revisit the valuation after the Revenue Application was submitted, specifically to resolve these classification issues and prevent this situation from arising. It is therefore minded to rely on the lower valuation of connection assets when setting connection charges under the OATS Rules provided that such a decision does not disadvantage customers. The ERC has not considered this issue in detail. However, in its response to this Draft Determination, the Regulated Entity is directed to comment on the practical implications of such a decision by the ERC, and in particular the impact on customer rates if the connection asset base that is used for valuation purposes is smaller than the connection asset base used for charging purposes.

5.12 ERC Analysis – Asset Disposals

5.12.1 The forecast disposal of assets must be taken into account in rolling forward the initial asset valuation to the beginning of the Third Regulatory Period. The Regulated Entity’s disposal program over the period 2009-10 is generally a consequence of the requirement in Section 8 of EPIRA to sell subtransmission and connection assets to qualified distribution utilities. The Act requires the sale price to be based on the earning potential of the assets rather than their book value.

5.12.2 Normal practice in accounting for disposals is to remove the disposed asset from the asset base at its book value (in this case the ODRC at the time of sale) rather than at the sale price and account for any difference in the income statement. However the reality is that, in most cases, the sale price under the EPIRA requirements is lower than the book value. The ERC considers that the Regulated Entity should not be forced to take a loss on the sale of the asset in these circumstances and that any difference between the book value and the sale price should be left in the asset base and amortized over the remaining life of the asset. This outcome is achieved if, at the time of sale, an asset is removed from the asset base at its sale price rather than its ODRC value.

5.12.3 No disposals of transmission or residual subtransmission assets should be provided for during the Third Regulatory Period, consistent with the ERC decision that residual subtransmission assets be included in the RAB as of January 1, 2011 and remain as assets of the Regulated Entity45.

45 ERC Resolution No 1, Series of 2009.


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5.13 ERC Decision Asset Disposals

5.13.1 It is not clear why the Regulated Entity is disposing of transmission assets in 2010. However, it is noted that the receipts from the sale of these assets as shown in Figure 4 of the Supplemental Report are much higher than shown in Table 11.4 of Annex A of the Revenue Application. As there is no provision in EPIRA requiring the sale of transmission assets, the ERC has decided to remove these assets from the RAB at their ODRC value of PhP 80.16 million, nominal.

5.13.2 The ERC has decided to accept the Regulated Entity’s disposal schedule, as shown in Figure 4 of the Supplemental Report. As these sales are in accordance with EPIRA requirements, assets have been removed from the RAB at sale price rather than the ODRC value.

5.14 ERC Analysis – Roll Forward CAPEX

5.14.1 It is necessary to roll forward SKM’s initial RAB asset valuation from December 31 2008 to December 31, 2010 in order to derive an opening RAB for the Third Regulatory Period. This roll-forward is undertaken outside of the ERC’s regulatory revenue model, which requires the opening RAB at the beginning of the Third Regulatory Period as an input. Furthermore, as residual subtransmission assets are also to be included in the RAB as of December 31, 2010, a roll forward of SKM’s residual subtransmission asset valuation is also necessary46.

5.14.2 In rolling forward the RAB asset valuation, the efficient CAPEX for 2009 and 2010, as recommended by the ERC’s regulatory reset expert, has been assumed. While the Regulated Entity’s budgeted CAPEX exceeds this, the ERC considers the excess expenditure to be inefficient and, consistent with the principles of PBR, inefficient expenditure should not be included in the RAB. Furthermore VAT is not included in the assumed CAPEX. The recovery of VAT is discussed in Section 3.13 and Section 5.22.

5.14.3 The residual subtransmission CAPEX shown in Schedule 12 of Annex A of the Revenue Application has been accepted. The only adjustment to this expenditure has been to remove the estimated VAT component.

5.15 ERC Preliminary Findings – Opening Regulatory Asset Base

5.15.1 The ERC has developed and used its own roll forward model that addresses the issues discussed in the above sections. The model has the following features:

• Unlike the model submitted with the Revenue Application, the model uses real 2010 PhP. All inputs are converted to real PhP before being applied in the model.

• The model separately rolls forward RAB and residual subtransmission assets and then combines to two asset bases for input into the ERC’s regulatory revenue model. The weighted average age of each

46 A roll forward of SKM’s connection asset valuation will also be required to reset the connection charges in

accordance with the OATS Rules. However, as setting connection charges is outside the scope of this Draft Determination, this roll-forward is not discussed.


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combined asset category is recalculated, taking into account the CAPEX over 2009-201047.

• CWIP is included in the model and assumed to be constant in real terms over the roll forward period. It is entered into the regulatory revenue model as a separate asset category that, like spares and land related asset categories, does not depreciate.

• The asset category transfers approved by the ERC in 2009 and shown in Figure 6 of the Supplemental Report are included in the model.

• Capitalized overheads in 2009 and 2010 were pro-rated across the other asset categories and thus, subject to depreciation.

5.15.2 On this basis, the ERC’s Preliminary Findings is to use the opening RAB shown in Table 5.7 as the basis for determining the MAR for the Third Regulatory Period. A breakdown of this opening RAB into the ERC’s standard asset categories is provided in Appendix C.

Table 5.7: Roll Forward of Initial Asset Valuation (PhP million, real 2010)

RAB Assets Residual Subtransmission

Assets

Total

Opening asset value 2009 155,566.361 13,103.95 168,670.31

Add transferred assets 2,016.98 (1,841.06) 175.92

Less disposals - (348.07) (348.07)

Add CAPEX 5,002.12 114.89 5,117.01

Less depreciation (5,775.39) (669.11) (6,444.50)

Closing asset value 2009/Opening value 2010 156,810.08 10,360.60 167,170.68

Add transferred assets - - -

Less disposals (80.16) (860.31) (940.47)

Add CAPEX 7,614.56 662.27 (8,276.83)

Less depreciation (5,978.69) (582.37) (6,561.69)

Closing asset value 2010/Opening value 2011 158,365.78 9,580.19 167,945.97 Note 1: SKM values, with the CWIP factor removed, CWIP added and inflated to 2010 PhP.

5.16 Weighted Average Cost of Capital

5.16.1 The WACC is used in the building block analysis to calculate the return on capital each year of the forecast regulatory period. Under Section 4.9 of the RTWR the return on capital is calculated as the rolled forward RAB plus the working capital (WC) allowance, both expressed in real terms, times the cost of capital expressed as a post-tax nominal ‘vanilla’ WACC. The multiplication of a real and nominal number provides a nominal cash flow for the building block analysis.

47 An input to the recalculation of the weighted average age was the ORC of transferred and disposed assets. It was

assumed that these assets were at mid-life and the ORC was thus estimated at twice the ODRC.


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5.16.2 It is important to realise that the RTWR specifies a post-tax nominal WACC because its requires the corporate income tax to be estimated as the forecast ‘actual’ corporate income taxes expected to be paid in the coming regulatory period. Thus the recovery of corporate income tax is not included in the WACC but rather the PBR methodology specified in the RTWR requires this to be one of the building blocks (or cash flows) which add to the MAR. Because of the provisions of RA 9511, NGCP is not required to pay corporate income tax. Therefore, the corporate income tax building block has been set to zero for the third regulatory period. Nonetheless, the WACC is still required to be estimated as the post-tax nominal ‘vanilla’ WACC.

5.16.3 This estimate of the regulatory WACC for this Draft Determination has been undertaken using market data from around the end of January 2010. As such it has allowed the ERC to explore any distortions in the market data resulting from the continuing uncertainty following the onset of the global financial crisis (GFC) in late 2008. The analysis suggests the market data from the normal sources continues to be relevant for the ERC decision process.

Methodology

5.16.4 The following changes to methodology are included (or excluded) in this Draft Determination, following further information and discussion provided by the Regulated Entity’s WACC expert, Professor van Zijl, in Schedule 5 to Annex A of the Revenue Application48, and in responses from Professor van Zijl and other stakeholders in the expository hearing and subsequent evidentiary hearing processes:

(a) Input values are derived using average market data over longer periods of time as these average out excess market volatility (particularly relating to increased volatility resulting from the GFC) and are more representative of the market data required to calculate the WACC for the Regulated Entity than are available in spot market measures.

(b) Adoption of the additional T factor in the development of the re-levering formulae to accommodate the differences between the tax rates on dividend income (an equity return) and on interest income (a return on debt) in the Philippines. This was a proposal in NGCP’s application suggested by Professor van Zijl. The additional formula is as follows:

11

i

e

tTt

−=

−

where et is the personal tax rate on equity returns and it is the personal tax rate on interest. Where these tax rates are equal the T factor calculates to the value of one, and the de-levering and re-levering formulae are as currently provided in clauses 4.9.7 and 4.9.8 of the RTWR.

48 NGCP WACC for Third Regulatory Period. Professor Tony van Zijl, London Economics

Consulting Group, December 8, 2009.


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(c) Adoption of the tax adjusted re-levering formula rather than the more simplified version in clause 4.9.7 of the RTWR. This was a proposal in the Revenue Application suggested by Professor van Zijl. The more complex formula is as follows:

Betae = Betaa x [1 + ((1 - tc) / T) x (debt/equity)]

This moves to have the re-levering formula equal to the de-levering formula in clause 4.9.8 of the RTWR, which is the more usual approach to the treatment of beta in financial market analysis.

(d) Non-adoption of the approach recently suggested by the DUs and now adopted by the ERC for the WACC analysis of DUs, whereby the ERC uses a regulatory WACC output from the 75% point in the range of calculated market values. For reasons including the provisions of RA 9511 and the adoption of the T factor, the ERC does not believe such an adjustment is currently warranted for the Regulated Entity’s regulatory reset analysis.

5.16.5 The ERC also explores the other formulae changes proposed by Professor van Zijl and from recent additional research published by Professor Aswath Damodaran, but while seeking additional comment from stakeholders following the issue of this Draft Determination, does not at this point propose to adopt the alternative WACC methodology proposed. The ERC notes that there are differences in approach seen in Professor van Zijl’s methodology and that of Professor Aswath Damodaran, which would benefit from further consultation.

5.16.6 The following paragraphs update the ERC’s WACC estimate for the regulated Entity to the end of January 2010.

Locked Parameters 5.16.7 In determining the WACC methodology under the RTWR, the ERC has set a

number of the variables used in the calculation of WACC at levels which represent estimates of average or good financial industry practice for financially viable companies. The reasons for this approach are provided in the RTWR, but in general relate to the difficulty in undertaking a statistically valid measure of these values in the Philippines marketplace, which is a relatively young and small market without historical market measures from a sufficiently long time period to provide statistical accuracy, and which has yet to show the trading liquidity which would improve these statistical measures. For the Third Regulatory Period one set value remains the same as required by clause 5.9.1 of the RTWR. Thus the Market Risk Premium (MRP) is set to 0.06 (or 6.0% pa).

5.16.8 Previously the gearing ratio was set at 50% funding by debt and 50% funding by equity, resulting in a debt/equity ratio of 1 or debt/(debt+equity) and equity/(debt+equity) ratios of 2. Submissions by industry participants suggest this level of gearing contains too much debt for an investment in transmission networks in the Philippines. The ERC remains of the view that it should initially unlock the gearing ratio to allow the effect of lower debt funding to be explored further. In the Issues Paper49 the ERC looked at a value of 15% for

49 Supra. Note 4


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debt funding which makes the equity funding 85%. Feedback during the public consultation process suggested the value should lie around the value of the current debt ratio for the Regulated Entity. Therefore the ERC has adopted a value of 14.4% for the debt ratio for this Draft Determination, as it understands this is approximately the current level of debt implicit in the Regulated Entity’s financing structure. Suggestions by the Regulated Entity on a more accurate measure in its comments following the issue of this Draft Determination would be helpful.

Market Parameters - Risk Free Rate in the Philippines

5.16.9 The discussion in clause 4.9.5 of the RTWR provides some comments on the approach to measure the risk free rate in the Philippines. Two measures are briefly explored here. Firstly the return on a PhP treasury bond resulting from the auction process undertaken by government. Secondly the return on a long-dated US treasury bill plus the yield difference between peso and US dollar bills available within the Philippines. The following paragraphs explore each outcome.

Direct Measure of Risk Free Rate in the Philippines 5.16.10 Information on the yield of the 5-year PhP treasury bond suggests the yield

resulting from the auction process for fixed rate treasury bonds on February 8, 2010 with a nominal yield of 6.23%pa., as sourced from the Banko Sentral Philippinas (BSP). The treasury bond auction process may not provide a yield which represents the return that would be available from a highly liquid secondary financial market outside of the government auction process. As such, the yield may not necessarily be a good representation of the returns expected from a long-term liquid risk-free investment by debt providers in the Philippines. The ERC notes the only yield data available at that auction was for a tenor of 5 years, but it would prefer to see data from a 10-year bond. However, given a “normal” yield curve (ie a slowly rising yield curve with a similar shape to Figure 5.3) is operative in the Philippines at this point (at least from the bond auction process), the risk free rate which is estimated from other techniques should lie close to, but most likely above, this rate.

5.16.11 Figure 5.3 also displays the yields on US dollar denominated bills auctioned by BSP for February 1 through 5, 2010. This yield difference is an approximate measure of the country risk premium (CRP) for the ERC’s WACC methodology, and a direct measure of the country risk premium for debt (CRPd) used in the method for estimating equity return proposed by Professor van Zijl. So the direct estimate of the CRPd in the Philippines using available data is around 3.15% pa. The ERC notes it would be better to take this difference on 10 year Philippine treasury bonds and US treasury bonds. This detailed data is to be sourced for the Final Determination.

Figure 5.3 Yield Curve for Philippines Treasury Bills and Bonds for February 2010


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Philippines Treasury Bills / Bonds vs US$ Bills / Bonds

R2 = 0.9661

R2 = 0.9602

-

1.00%

2.00%

3.00%

4.00%

5.00%

6.00%

7.00%

- 1.0 2.0 3.0 4.0 5.0 6.0

Tenor (years)

Yiel

d (%

pa)

Peso Yield (% pa) US$ Yield (% pa)

Log. (Peso Yield (% pa)) Log. (US$ Yield (% pa))

Indirect Measure of Risk Free Rate in the Philippines 5.16.12 In order to apply the high-liquidity, risk-free rate from the US in the

Philippines, the estimate needs to remove the US inflation effects and add back the Philippines inflation effects. Also the estimate needs to add a yield premium associated with investing in the Philippines rather than in the US. This CRP can be best measured through the yields offered on US dollar bonds in the Philippines and US dollar bonds in the USA for the same duration, maturity and exercise date. Reasonable liquidity in both markets is also required. This difference represents the risks of investing in the Philippines, rather than investing in another market with perceived lower risks, in this case suggested to be the US. This measure excludes foreign exchange risk. The following paragraphs isolate estimates of this data.

Risk Free Rate in the US

5.16.13 Data was drawn from the Federal Reserve of the US statistical data Table U15 of the average yields for February 18, 2010 for 10 year maturity treasury bonds. The average yield was a nominal yield of 3.71%pa50. The range of values at one standard deviation was between 3.24%pa and 2.37%pa. While the ERC has used this data source for this Draft Determination, it would prefer to use data on specific bond yields around the determined date for analysis of the WACC for the Final Determination, which can be sourced from the Bloomberg data service, where this data is available and displays reasonable liquidity. Figure 5.4 shows the available data as well as the CPI-adjusted 10-year bond yields.

Figure 5.4: Yield Curve for US 10-year US Dollar Treasury Bonds for February 2010

50 Average January 5 to February 17, 2010.


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US Treasury Bonds (Nominal vs CPI Adj)

R2 = 0.9754

R2 = 0.9867

(2.00%)

(1.00%)

-

1.00%

2.00%

3.00%

4.00%

5.00%

6.00%

0 5 10 15 20 25 30 35

Tenor (years)

Yiel

d (%

pa)

Nominal CPI Adj Log. (Nominal ) Log. (CPI Adj)

CPI in the USA 5.16.14 This nominal yield includes US inflation. Data on the US inflation rate was

also sourced from the US Department of Labor – Bureau of Statistics, for All Items, US Cities average, non-seasonally adjusted. Figure 5.5 shows that the monthly inflation rate using data between January 2002 and January 2010. The inflation rate in the US has been quite volatile over this period, and while it dropped rapidly as a result of the GFC, and becoming negative in the second quarter of 2009, it has recovered to positive levels more recently.

Figure 5.5: US Inflation Rate (% change by month on previous year)

USA Annual Inflation Rate

-3.0%

-2.0%

-1.0%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

Nov-01 Mar-03 Aug-04 Dec-05 Apr-07 Sep-08 Jan-10

Month

Ann

ual C

PI C

hang

e fr

om S

ame

Mon

th L

ast Y

ear (

% p

a)

Spot Jan '06

Spot Oct '05

Jul '04

Spot Dec '08

Spot Jun '09

Spot Dec '09


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5.16.15 Table 5.8 provides the spot, six-month average and twelve-month average US inflation rates to the end of January 2010. The effect of the dramatic reduction in the last quarter of 2009 is evident.

Table 5.8: Average US Inflation Rate to end January 2010 (% pa) Period for Average Average of Monthly Inflation Rates

(% per annum)

Spot 2.72%

6 month (0.08%)

12 month (0.34%)

5.16.16 Data was drawn from the Federal Reserve of the US statistical data Table U15 of the average yields for February 2010 for 10-year maturity inflation-indexed bonds (refer Figure 5.4 above). The average yield on a 10-year CPI adjusted bond was a yield of 1.37%pa51. Using the Fischer Equation the calculated inflation rate implied by the difference in the average of the yields for nominal and inflation-indexed US bonds suggest USA inflation was 2.31% pa around the end of January 2010.

CPI in the Philippines

5.16.17 Information on the CPI in the Philippines sourced, from the National Statistics Office (NSO) of the Philippines, indicates that the average inflation rate over the last six months has fallen rapidly from a peak of around 12.2% pa at the end of the 3rd quarter of the calendar year 2008 to around 0.1% pa at the end of August 2009 (refer Figure 5.6). The Philippines inflation rate, similar to the data from the US, fell in response to the reduction in consumer demand due to the uncertainties resulting from the GFC, and has since rebounded following more positive news on consumer demand.

Figure 5.6: Philippines Inflation Rate (% pa)

Philippines Annual Inflation Rate

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

Nov-01 Mar-03 Aug-04 Dec-05 Apr-07 Sep-08 Jan-10

Month

Ann

ual C

PI C

hang

e fr

om

Sam

e M

onth

Las

t Yea

r (%

pa)

Spot Oct '05

Spot Jan '06

Jul '04Spot Dec '08

Spot Jun '09

Spot Jan '10

51 Average January 5 to February 17, 2010.


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5.16.18 Table 5.9 provides the spot, six-month average and twelve-month average Philippines inflation rates to the end of January 2010. The effect of the dramatic reduction in the last quarter of 2008 and first quarter of 2009 is evident.

Table 5.9: Average Philippines Inflation Rate to end January 2010 Period for Average Average of Monthly Inflation Rates

(% per annum)

Spot 4.26%

6 month 2.33%

12 month 3.12%

5.16.19 The difference in response to the CPI measured in the US and that measured in the Philippines is clearly seen in Figures 5.5 and 5.6 respectively. The drop in the Philippines is lagging slightly the drop seen in the US, as is the subsequent rise on improved consumer spending.

Philippines Country Risk Premium

5.16.20 The ERC has been accessing the CRP data from a PricewaterhouseCoopers (PwC) source for the period from around 2003 to end of 2007, for development of regulatory WACCs for both the Regulated Entity and DUs. The data is provided in Figure 5.7.

Figure 5.7: Philippines CRP (% pa)


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Philippines Country Risk Premium

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

Q1 200

0

Q3 200

0

Q1 200

1

Q3 200

1

Q1 200

2

Q3 200

2

Q1 200

3

Q3 200

3

Q1 200

4

Q3 200

4

Q1 200

5

Q3 200

5

Q1 200

6

Q3 200

6

Q1 200

7

Q3 200

7

End of Quarter (Commencing Q1 2000)

CR

P (%

pa)

Lower Limit @ 1 StdDev = 2.5%

Upper Limit @ 1 StdDev = 5.1%

5.16.21 The ERC is hoping to access additional CRP data from this source for the 2010 year for Final Determination. The ERC notes that Professor Aswath Damodaran uses a similar technique to PwC in his recent analysis of MRP published in January 201052.

Philippines Risk Free Rate – Indirect Measure 5.16.22 An estimate of the risk-free rate in the Philippines is thus possible from the

following formula: rPhil = (1+rUS) / (1+CPIUS) x (1+CPIPhil) x (1+CRP) – 1

where:

rUS = 0.0364 to 0.0377 (using +/- one standard deviation of the 30 business days to February 17, 2010);

CPIUS = -0.0105 to 0.0037 (using +/- one-half of a standard deviation of the twelve month average to December 2009);

CPIPhil = 0.0193 to 0.0430 (using +/- one-half of a standard deviation of the twelve month average to January 2010); and

CRP = 0.016 to 0.023 (based on +/- one standard deviation of last 2 years).

Thus the estimate of the risk-free rate in the Philippines using an indirect measure based on offshore US risk-free rate data, relative inflation rates and a CRP estimate is between 8.4% pa and 10.3% pa in nominal terms.

Review of Direct and Indirect Measure of Philippines Risk Free Rate

5.16.23 The measure achieved by an indirect measure of the risk-free rate suggests a range from 8.4%pa to 10.3%pa. The direct measure suggests a risk-free rate of about 6.2%pa (see above). The measures are not consistent within the range of estimates, but are influenced by the use of a twelve-month average for

52 Refer “packet1.pdf” file at http://pages.stern.nyu.edu/~adamodar/pdfiles/eqnotes/packet1.pdf .


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inflation in the indirect measure. This is being compared to a Philippines bond auction on a single day in the direct measure, and the fact that the Philippines US dollar denominated bonds are Brady Bonds, which partially eliminate the country risk effects through a US government guarantee. Hence this reduces the yields required by investors. The ERC has some concern that the extreme liquidity pumped into the global markets due to the GFC is now beginning to have an impact on the supply and demand for the issue of bonds (demand exceeding supply), with the effect that yields are falling in the mid-term. Given the volatility of the markets due to the GFC, which the ERC believes should be a short to mid-term issue, it is inclined to use the twelve-month average CPI measures to develop estimates of the risk-free rate using an indirect measure of market data. Thus, without committing to a final value for the risk-free rate, the ERC in undertaking its analysis for this Draft Determination uses a range of values derived from an indirect measure which lie between 8.4%pa and 10.3%pa.

Measurement of Benchmark Equity Betas

5.16.24 A review of Bloomberg data on electricity transmission companies for the Final Determination for the Second Regulatory Period in June 2006 suggested there are not many electricity transmission companies of similar operational characteristics, which are traded in the markets. Hence, the statistics on the equity beta are note particularly accurate. Table 5.10 suggests a range of the derived asset beta of between 0.60 and 0.68 with a mean of 0.638. This is after application of the formula in clause 4.9.8 of the RTWR.

Table 5.10: Overseas Transmission Company Equity and Asset Betas


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Effective Tax Rate Market Net Gearing Equity Beta Asset Beta Asset Beta

Company Country

Corporate Tax Rate (%)

- trailing 12 month (%)

Capitalisation ($M) Debt ($M) (D/E)

Corporate Tax Rate Used (%) Bloomberg Full Set Selected

1 2 3 4 5 9 10 12 13 # 15

Electricity Transmission Hamada Hamada Formula Formula

TRANSENER SA-B ARGENTINA 35.0% -3.10 820.11 1,688.83 205.93% 35.0% 0.83 0.36 0.36CIA DE TRANSMISSAO DE ENE-PF BRAZIL 15.0% 30.32 4,274.26 58.64 1.37% 30.3% 0.92 0.91 0.91BORALEX INC -CL 'A' CANADA 21.0% 8.99 252.81 65.29 25.83% 9.0% 0.62 0.50 0.50INTERCONEXION ELECTRICA SA COLOMBIA 36.7% 41.35 5,579,587.00 1,708,414.00 30.62% 41.4% 1.13 0.96 0.96RED ELECTRICA DE ESPANA SPAIN 35.0% #N/A N.A. 3,496.73 1,951.49 55.81% 35.0% 0.80 0.59 0.59

Total Electricity Transmission Mean 63.91% 0.86 0.66 0.663Total Electricity Transmission Median 30.62% 0.83 0.59 0.588

Gas Transmission

AUSTRALIAN PIPELINE TRUST AUSTRALIA 30.0% -24.49 1,160.21 988.93 85.24% 30.0% 0.43 0.27GASNET AUSTRALIA GROUP AUSTRALIA 30.0% 27.96 358.93 609.26 169.74% 28.0% 0.58 0.26SNAM RETE GAS ITALY 33.0% 39.67 6,999.69 2,859.00 40.84% 39.7% 0.53 0.43SUI SOUTHERN GAS CO LTD PAKISTAN 35.0% 29.34 20,504.37 5,864.17 28.60% 29.3% 0.93 0.77

Total Electricity Transmission Mean 81.11% 0.62 0.43Total Electricity Transmission Median 63.04% 0.56 0.35

Total Transmission Mean - gas and electricity 71.55% 0.75 0.56Total Transmission Median - gas and electricity 40.84% 0.80 0.50

Electricity Vertically Integrated

AUSTRALIAN ENERGY LIMITED AUSTRALIA 30.0% 0.00 97.97 -3.26 -3.33% 30.0% 0.29 0.29CENTRAIS ELETRICAS BRAS-PR B BRAZIL 15.0% 208.47 22,188.25 25,212.12 113.63% 15.0% 1.24 0.63CIA ENERGETICA DE PER-PREF A BRAZIL 15.0% 33.15 1,042.60 901.90 86.51% 33.2% 0.41 0.26ELETROPAULO METROPOLITA-PREF BRAZIL 15.0% 239.88 3,918.43 3,181.59 81.20% 15.0% 1.15 0.68 0.68LIGHT SERVICOS DE ELETRICID BRAZIL 15.0% 129.71 1,968.46 4,060.03 206.25% 15.0% 1.15 0.42 0.42INTERNATIONAL POWER PLC BRITAIN 30.0% 21.07 4,055.72 2,786.00 68.69% 21.1% 1.01 0.66SCOTTISH & SOUTHERN ENERGY BRITAIN 30.0% 31.75 9,334.68 1,667.30 17.86% 31.8% 0.61 0.54CIA GENERAL DE ELECTRICIDAD CHILE 16.5% 14.65 1,006,950.00 851,272.73 84.54% 14.7% 0.68 0.39ENERSIS SA CHILE 16.5% 42.88 4,114,048.00 3,118,413.10 75.80% 42.9% 1.25 0.87EMPRESA ELECTRICA ANTOFAGAST CHILE 16.5% 14.56 39,777.10 -440.70 -1.11% 14.6% #N/A N.A.CLP HOLDINGS LTD HONG KONG 17.5% 17.40 105,240.40 16,254.00 15.44% 17.4% 0.46 0.41AEM TORINO SPA ITALY 33.0% 33.74 1,007.64 739.00 73.34% 33.7% 0.76 0.51CHUBU ELECTRIC POWER CO INC JAPAN 30.0% 37.43 2,074,253.00 3,326,620.00 160.38% 37.4% 0.53 0.27HOKURIKU ELECTRIC POWER CO JAPAN 30.0% 39.17 566,258.40 977,289.00 172.59% 39.2% 0.49 0.24TENAGA NASIONAL BHD MALAYSIA 28.0% 18.83 34,923.65 27,139.60 77.71% 18.8% 1.13 0.69 0.69CONTACT ENERGY LTD NEW ZEALAND 33.0% 32.80 3,834.62 1,075.47 28.05% 32.8% 0.97 0.82KARACHI ELECTRIC SUPPLY PAKISTAN 35.0% #N/A N.A. 116,603.90 35.0% 0.88 0.88IRKUTSKENERGO RUSSIA 24.0% 37.64 63,980.10 -169.22 -0.26% 37.6% 0.88 0.88KOREA ELECTRIC POWER CORP SOUTH KOREA 27.0% 38.20 26,079,730.00 18,139,243.00 69.55% 38.2% 0.66 0.46ALLETE INC UNITED STATES 35.0% 17.22 1,331.66 197.90 14.86% 17.2% 0.97 0.86AVISTA CORP UNITED STATES 35.0% 35.68 926.09 1,082.34 116.87% 35.7% 0.95 0.54BLACK HILLS CORP UNITED STATES 35.0% 29.48 1,166.73 709.24 60.79% 29.5% 0.95 0.66DPL INC UNITED STATES 35.0% 31.66 3,276.15 1,928.70 58.87% 31.7% 0.86 0.61DUKE ENERGY CORP UNITED STATES 35.0% 30.57 26,027.53 15,914.00 61.14% 30.6% 0.79 0.56FIRSTENERGY CORP UNITED STATES 35.0% 46.73 16,284.02 11,071.84 67.99% 46.7% 0.69 0.50FPL GROUP INC UNITED STATES 35.0% 23.58 16,039.02 10,072.00 62.80% 23.6% 0.67 0.45TXU CORP UNITED STATES 35.0% 26.30 24,414.51 13,343.00 54.65% 26.3% 0.75 0.53

Total Vertically Integrated Mean 70.19% 0.81 0.56 0.596Total Vertically Integrated Median 68.34% 0.83 0.54 0.677

Total Selected Mean Total Selected Mean 0.638Total Selected Median Total Selected Median 0.633

NotesMarket Cap & Gearing based on Bloomberg data as at 3 February 2006

De-Levering to Asset Beta 5.16.25 In Table 5.10, the equity betas measured in overseas equity markets are de-

levered using the formula in clause 4.9.8 of the RTWR. The debt/equity and effective tax rates are required for the overseas transmission companies (or countries) to calculate the asset betas. The range of asset betas is provided in this table.

5.16.26 During its analysis of regulatory WACC for the Regulated Entity, the ERC noted that its use of the Hamada formula may distort the derivation of the asset beta from the observed equity betas. However, given the lack of specific data on the tax arrangements of the countries from which equity betas are measured, including the effective tax rate, corporate tax rate and T factor this distortion is considered small. In this instance the corporate T factor mentioned above is taken to be equal to 1.0.

Selecting an Asset Beta

5.16.27 Without committing to a decision on an appropriate asset beta for the Regulated Entity, the apparent range of the asset beta that might be applicable to the Regulated Entity for the Third Regulatory Period is between approximately 0.42 and 0.86 which is minus and plus one standard deviation of the mean of 0.638. The ERC notes that this value of asset beta is somewhat higher than the regulatory asset beta used by the Australian Energy Regulator


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(AER) in its transmission decisions, which has been set at 0.4. Prior to the AER assuming regulatory responsibility for electricity transmission assets, the Australian Competition and Consumer Commission (ACCC) also determined that an asset beta of 0.4 was reasonable. They have both also accepted that the resulting equity beta from their WACC analysis is 1.0.

5.16.28 The ERC will source new and more up-to-date Bloomberg data to develop the asset beta for the Final Determination.

5.16.29 The ERC flags that, following the Regulated Entity’s submission in Schedule 5 of Annex A of the Revenue Application and previous submissions from Professor van Zijl, the ERC’s view of the de-levering formula that should be applied to estimate the regulatory WACC for the Third Regulatory Period has changed. The ERC invites stakeholder comment on this change. The formula described in the paragraphs below has been used for this Draft Determination.

Re-Levering to NGCP Equity Beta

5.16.30 The formula in clause 4.9.7 of the RTWR to re-lever the asset beta to an equity beta for regulatory purposes using the debt/equity ratio is defined as follows:

Betae = Betaa x [1 + (debt/equity)]

5.16.31 Following public consultation on the Issues Paper relating to this Draft Determination, the ERC believes the formula in clause 4.9.7 of the RTWR should be changed to the formula proposed by the Regulated Entity (which was derived from analysis by Professor van Zijl in Schedule 5 of Annex A of the Revenue Application, using the implied ERC assumptions,). The formula used to re-lever the asset beta to an equity beta for regulatory purposes using the debt/equity ratio of 14.4%/85.6% or 0.1685, the following formula applies.

Betae = Betaa x [1 + ((1 - tc) / T) x (debt/equity)]53

It should be noted that the corporate income tax rate that applies to the Regulated Entity is now zero, so the formula simplifies to the following.

Betae = Betaa x [1 + (1 / T) x (debt/equity)]

Using the personal tax rate on dividends of 10% and the personal tax rate on interest income of 20%, the value of T derived using the formula in paragraph 5.16.4(b) above is 0.89. Thus the Regulated Entity’s equity beta is assumed to lie between 0.71 and 0.81, with a mid range value of 0.76. Thus, using the Regulated Entity’s proposed re-levering formula, there is a 1.8% increase in the equity beta estimate using the methodology proposed by the Regulated Entity, at this relatively low gearing ratio.

Estimated Range of Return on Equity 5.16.32 Using the formula in clause 4.9.4 of the RTWR and the data ranges above,

the range of the return on equity to be used for regulatory purposes lies between the values shown in Table 5.11, depending on the equity beta formula used. This is an estimate of the range of the return on equity investors would expect to receive for investing in an electricity transmission business in the Philippines.

53 T is defined by the formula in paragraph 5.16.4(b)


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Table 5.11: Return on Equity using Capital Asset Pricing Model (CAPM) Formulae

Formula for Equity Beta Low Range Mid Range High Range

As clause.4.9.7 of RTWR 13.17% 13.85% 14.56%

As paragraph 5.16.31 13.28% 13.93% 14.61% Note : All values are nominal % pa.

Estimated Range of Debt Margin 5.16.33 At present the ERC does not have a lot of data on the debt margin above the

risk-free rate that a debt provider would expect for provision of debt to an electricity transmission business in the Philippines. For this Draft Determination the ERC continues to make the assumption that a large private company in the Philippines with a similar risk profile to the Regulated Entity can access debt at a debt margin of between 2.25%pa and 2.75%pa above the risk free rate. This is in line with the ERC’s most recent work on the DUs. The ERC recognizes that a pure transmission company should have better access to debt funds than a DU, which is a combined wires and retail electricity business (and sometimes generation assets), simply because the revenue stream it has access to is likely to be more stable and have less default risk than the revenues for a DU.

5.16.34 The ERC seeks comment from stakeholders on the debt margin it should use and will further explore the value of the debt margin to use for the Regulated Entity in developing a regulatory WACC for the Final Determination.

Estimated Range of Return to Debt 5.16.35 Using this range as the assumed debt margin in the Philippines, the cost of

debt for an electricity transmission company in the Philippines lies between 10.4% pa and 13.3% pa (nominal) (see clause 4.9.10 of the RTWR). The mid-point value used for the return to debt for this Draft Determination is 11.88% pa (nominal).

Estimated Range of WACC

5.16.36 Using the above data and the formula in Clause 4.9.3 of the RTWR, the estimate of the WACC to be used for regulatory purposes as at end January, 2010 would lie within the range of 13.0% pa and 14.7% pa, on a post-tax nominal basis or, from the same input data, at between 12.7% pa and 14.5% pa on a nominal vanilla WACC basis. The reason it is not the same is because while the corporate income tax rate is now zero, the T factor influences the cost of equity required by the end investor and changes the post-tax nominal WACC formula. The mid-point regulatory WACC value calculation using the RTWR vanilla WACC formula is summarized in Figure 5.8 below.

Figure 5.8: Summary of Regulatory WACC Estimate (% pa post-tax nominal and nominal vanilla)


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Market Risk Premium6.00%

Company Equity Risk Premium4.55%

Cost Levered Company Beta (1) Cost of Equity 85.6% (5)

0.758 13.93%of

EquityRisk Free Rate (2)

9.38%WACC WACC13.85% 13.63%

Risk Free Rate (2) (post-tax nominal) (vanilla)9.38%

Levered Company Cost of Debt11.88%

Cost Levered Debt Premium (3)2.50%

of Net Cost of Debt11.88% 14.4% (5)

DebtMarginal Tax Rate (4)

0.0%

T Factor0.89

5.16.37 Table 5.12 below provides the summary of the range and mid-point

calculation for the regulatory WACC for the Draft Determination using the formula in the RTWR and the adjusted re-levering, CAPM and WACC formula incorporating the T factor proposed by the Regulated Entity as developed by Professor van Zijl.

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Table 5.12: Regulatory WACC Summary

NGCP Draft Determination Regulated WACC Estimate - Base on Peso Debt FinancingWACC Calculation WorksheetInput only in shaded cells

Paramaters Low Mid High

Gearing (Debt) ratio D/(D+E) 19.4% 14.4% 9.4%Equity ratio E/(D+E) 80.6% 85.6% 90.6%Debt to Equity D/E 0.241 0.168 0.104Asset beta (degeared empirical beta) ßa 0.638 0.638 0.638Debt beta ßd 0.080 0.180 0.280

Risk free rate (nominal - US$ 10 Year Bond Yields in USA) 3.64% 3.71% 3.77%Country Risk Premium for Equity (excluding FX Risk) CRPe 1.56% 1.94% 2.32%Risk free rate used in WACC Rf 8.42% 9.38% 10.34%

Debt Margin DM 2.00% 2.50% 3.00%Cost of debt (pre-tax nominal peso terms) Kd 10.42% 11.88% 13.34%Market Risk Premium (Developed Country) Rm - Rf 6.00% 6.00% 6.00%Corporate tax rate tc - - -

Inflation rate (Philippines) iPhil 1.93% 3.12% 4.30%Inflation Rate (USA) iUSA (1.05%) (0.34%) 0.37%Income Tax Rate on Interest Income ti 0.200 0.200 0.200Income Tax Rate on Dividend Income td 0.100 0.100 0.100T Factor, where T = (1-ti)/(1-te) T 0.889 0.889 0.889Calculated Equity (Regeared) Betas Formula Low Mid HighEquity Beta (1) Simple No Tax Adjustment - RTWR 1Equity Beta (2) Simple Tax Adjustment 2Equity Beta (3) Simple No Tax Adjustment & T Factor - Annex F NGCP 3 0.81 0.76 0.71Equity Beta (4) Complex No Tax Adjustment & T Factor - ERC & Prof. van 4

Other Parameters Low Mid HighEquity beta (geared beta) ße

Cost of Equity (post-tax nominal) Ke

Equity beta (geared beta) using Annex F NGCP ße 0.81 0.76 0.71Cost of Equity (post-tax nominal) using Prof van Zijl Ke 13.28% 13.93% 14.61%Equity beta (geared beta) using ERC extension of Prof van Zijl ße

Cost of Equity (post-tax nominal) using Prof van Zijl Ke

WACC Matrix - Commercial Practice & Prof van ZijlPost-tax nominal 12.98% 13.85% 14.65%Post-tax real 10.84% 10.41% 9.92%Pre-tax nominal 12.98% 13.85% 14.65%Pre-tax real 10.84% 10.41% 9.92%

Vanilla WACC (nominal) 12.73% 13.63% 14.49%

Regulatory WACC Using RTWR Methodology but Re-lever using Prof.

van Zijl

Comments on Data Sources and WACC Estimate

5.16.38 As required by Section 5.9 of the RTWR, the ERC will seek further comment on the data sources and the methods of data development to arrive at an estimate of the regulatory WACC for the Final Determination.

Recalculation Point Using Market Data 5.16.39 In a PBR analysis, the ERC must undertake a forward looking projection of

the Regulated Entity’s cash flow requirements to assist in setting the MAR for the coming regulatory period. It is not in the ERC’s skill set to forecast how debt and equity markets will measure the risks of any particular investment in any particular future period. Indeed, this is difficult for the financial community with all the skills and experience that they have available.


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5.16.40 Thus, the ERC must measure a WACC at a point in time using the most objective data available to it. This WACC is then assumed to apply at a constant rate into the future over the coming regulatory reset period. Obviously, the closer this “point in time” measurement is made to the commencement of the relevant regulatory period, the more likely it is to be representative of the beginning of the regulatory period of concern.

5.16.41 The ERC has undertaken this initial estimate of the WACC to be used for setting the NGCP revenue cap for the period from January 1, 2011, at the notional date of January 31, 2009 in the Issues Paper, at June 30, 2009 in the Position Paper, and now January 31, 2010 in this Draft Determination. The majority of the input data for the WACC is sourced from around each of these dates.

5.16.42 The ERC is of the view that the closest date at which the market measures for inputs to the WACC calculation should be updated to develop a final view of the WACC to be applied for the whole of the Third Regulatory Period, is for data gathered around July 31, 2010. This date allows some time for the ERC to complete the calculations and release its Final Determination, which is currently scheduled to occur by October 1, 2010.

Comments on Methodology and Further Refinement

5.16.43 In the Position Paper, the ERC noted that the WACC increased with increasing debt/equity ratio. The ERC believes this first order impact is what the Regulated Entity is referring to in its submission in Schedule 5 of Annex A of the Revenue Application. However, following further analysis, this effect is not an asset beta issue, rather a corporate income tax issue which arose once RA 9511 is implemented. The ERC notes this outcome is counter-intuitive given the WACC formula in Clause 4.9.3 of the RTWR, but can be explained by the following points:

(a) Where corporate income tax is required to be included in the analysis, the deductibility of interest payments on debt provides a tax shield in the cash flow analysis, meaning that the required equity return is lower and the WACC falls as debt rises and the tax shield rises;

(b) Where corporate income tax is set to zero, as is required under RA 9511, no tax shield is available in the cash flow analysis and higher debt means higher risk, and equity beta rises faster than the weighted lower debt cost where the simplified WACC formula in the RTWR are used, allowing WACC to increase in a counter intuitive manner; and

(c) The outcomes arise from the elimination by government of the requirement for NGCP to pay corporate income tax through promulgation of RA 9511, and the use of simplified formula for the return to debt and return to equity used in the RTWR, or as modified by this Draft Determination (and prior to the consideration of further stakeholder comments).

5.16.44 The ERC is of the view there is sufficient flexibility in Section 5.9 of the RTWR to allow the above changes to the debt/equity ratio and the T factor in the calculation of the WACC formula for the Third Regulatory Period. Notwithstanding the ability to change the formula


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in Clause 4.9.7 of the RTWR in the current process to something closer to that proposed by Professor van Zijl, it would be preferable undertake further public consultation during the Third Regulatory Period before amending the WACC formula further for the Fourth Regulatory Period. The formulae for examination under such a review include those for the return on equity using the CAPM in clause 4.9.11 and for the return on debt in Clause 4.9.10 of the RTWR. The following analysis explores the use of Professor van Zijl’s proposed formula provided in Schedule 5 of Annex A of the Revenue application.

Alternative Methodology Proposed by Professor van Zijl 5.16.45 Professor van Zijl advocates the use of the following formula for calculation

of the regulatory WACC under a PBR methodology.

The T factor calculated as follows:

11

i

e

tTt

−=

−

where et is the personal tax rate on equity returns, it is the personal tax rate on interest.

The equity beta calculated as follows: Betae = Betaa x [1 + ((1 - tc) / T) x (Dm / Em)]

where:

Betaa = the asset beta resulting from a study of global market data and the use of the same formula as directly above;

tc = the corporate tax rate for that business (expressed in decimal terms);

Dm = the amount of debt funding in the capital structure of that business; and

Em = the amount of equity funding in the capital structure of that business.

The return to equity calculated as follows: re = rf x T + Betae x TAMRP

where:

re = the nominal cost of equity;

rf = risk free rate estimated for a developed economy (not using the method adopted by the ERC, but likely the USA risk free rate as proposed by Professor Aswath Damodaran);

Betae = the Equity Beta for the electricity transmission business as calculated in the above formula; and

TAMRP = the Tax-Adjusted Market Risk Premium, using the following formula.

The TAMRP calculated as follows: TAMRP = MRPdeveloped + (1-T) x rf + CRPdebt x RVE

where:

MRPdeveloped = the market risk premium for a developed economy (not using the 6% adopted by the ERC, but likely the USA MRP as proposed by Professor Aswath Damodaran at 4.82%);

rf = risk free rate estimated for a developed economy (not using the method adopted by the ERC, but likely the USA risk free rate as proposed by Professor Aswath Damodaran);

CRPdebt = Yield spread between Peso long term T bond and US$ long term T bond issued by the Philippines government; and


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RVE = Relative volatility of equity (likely the % of NGCP’s revenue sourced within the Philippines divided by the % of Philippines GDP which is local revenue, rather than export revenue, as proposed by Professor Aswath Damodaran).

5.16.46 The remaining formulae proposed by Professor van Zijl are as for the formulae in the RTWR. In effect, he is proposing to move the estimate of the CRP from the calculation of risk free rate (which impacts both the return on equity and return on debt), to only being included in the TAMRP factor in the return to equity.

5.16.47 The ERC has estimated the range of values and mid-point of the regulatory WACC using these formulae to arrive at the value in Table 5.13 which is comparable to the outcomes in Table 5.12.

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Table 5.13: Professor van Zijl’s Regulatory WACC Estimate

NGCP Draft Determination Regulated WACC Estimate - Base on Peso Debt FinancingWACC Calculation WorksheetInput only in shaded cells

Paramaters Low Mid High

Gearing (Debt) ratio D/(D+E) 19.4% 14.4% 9.4%Equity ratio E/(D+E) 80.6% 85.6% 90.6%Debt to Equity D/E 0.241 0.168 0.104Asset beta (degeared empirical beta) ßa 0.638 0.638 0.638Debt beta ßd 0.080 0.180 0.280

Risk free rate (nominal - US$ 10 Year Bond Yields in USA) 3.64% 3.71% 3.77%Country Risk Premium for Equity (excluding FX Risk) CRPe 1.56% 1.94% 2.32%Risk free rate used in WACC Rf 8.42% 9.38% 10.34%

Debt Margin DM 2.00% 2.50% 3.00%Cost of debt (pre-tax nominal peso terms) Kd 10.42% 11.88% 13.34%Market Risk Premium (Developed Country) Rm - Rf 3.82% 4.82% 5.82%Corporate tax rate tc - - -

Inflation rate (Philippines) iPhil 1.93% 3.12% 4.30%Inflation Rate (USA) iUSA (1.05%) (0.34%) 0.37%Income Tax Rate on Interest Income ti 0.200 0.200 0.200Income Tax Rate on Dividend Income td 0.100 0.100 0.100T Factor, where T = (1-ti)/(1-te) T 0.889 0.889 0.889Country Risk Premium for Debt CRPd 2.65% 3.15% 3.65%Percentage NGCP Revenue in Philippines Rphil 100.00% 100.0% 100.00%Export Revenue Percentage of GDP GDPphil 13.87% 23.87% 33.87%Lambda λ 1.161 1.31 1.512Tax-Adjusted Market Risk Premium TAMRP 7.83% 10.00% 12.49%

Calculated Equity (Regeared) Betas Formula Low Mid HighEquity Beta (1) Simple No Tax Adjustment - RTWR 1Equity Beta (2) Simple Tax Adjustment 2Equity Beta (3) Simple No Tax Adjustment & T Factor - Annex F NGCP 3Equity Beta (4) Complex No Tax Adjustment & T Factor - ERC & Prof. van 4 0.81 0.76 0.71

Other ParametersEquity beta (geared beta) ße

Cost of Equity (post-tax nominal) Ke

Equity beta (geared beta) using Annex F NGCP ße

Cost of Equity (post-tax nominal) using Prof van Zijl Ke

Equity beta (geared beta) using ERC extension of Prof van Zijl ße 0.81 0.76 0.71Cost of Equity (post-tax nominal) using Prof van Zijl Ke 13.83% 15.92% 18.08%

WACC Matrix - Commercial Practice & Prof van ZijlPost-tax nominal 13.42% 15.55% 17.79%Post-tax real 11.28% 12.06% 12.93%Pre-tax nominal 13.42% 15.55% 17.79%Pre-tax real 11.28% 12.06% 12.93%

Vanilla WACC (nominal) 13.17% 15.34% 17.63%

Regulatory WACC Using Modified Methodology proposed by Prof. van Zijl

5.16.48 The ERC seeks further clarification on the formula the Regulated Entity is

proposing for the regulatory WACC calculation, and the data sources proposed to populate these formula. It also seeks comment on whether the ERC’s interpretation of the approach is robust or needs modification. Submissions from other stakeholders or the public are encouraged.

5.16.49 The final addition to the WACC methodology proposed by Professor van Zijl is the addition of an ‘uncertainty’ factor relating to errors in the estimating process. The proposal was to add 2% pa to the WACC on the basis it was


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better to over-provide and encourage investment, than to under-provide and have investment curtailed due to poor returns to the debt and equity providers. The ‘uncertainty’ factor allows for errors in the WACC calculation including for:

(a) Parameter error;

(b) Model error;

(c) Market frictions;

(d) Timing flexibilities;

(e) Firm resource constraints; and

(f) Regulatory decision making.

5.16.50 At present the ERC does not accept the value proposed to compensate for these uncertainties, nor in the need to compensate for all or any of these issues. The Regulated Entity may submit further argument on these matters in its submissions following the release of this Draft Determination.

5.17 Working Capital

5.17.1 Working capital is required by the Regulated Entity to compensate for the timing differences between when it incurs a cost and when it receives the revenue to cover that cost. In Schedule 10 of Annex A of the Revenue Application, the Regulated Entity submitted a report from PwC Financial Advisors (PwC FA) on the amount of working capital that the Regulated Entity would require during the Third Regulatory Period54. The report surveyed a number of approaches to estimating working capital and concluded that the lead-lag method was the most appropriate. On this basis it determined that the Regulated Entity’s average working capital requirement was 7.29% of net operating expenditures.

5.17.2 The PwC FA report explicitly stated that this average working capital requirement should be multiplied by the Regulated Entity’s operating expenditure, excluding bad debts, to obtain the amount of working capital required for the business to run efficiently55.

5.17.3 In addition to the PwC FA report the Regulated Entity submitted a report from the London Economic Consulting Group (LECG) on the level of bad debts that the Regulated Entity was likely to incur during the Third Regulatory Period56. The LECG report estimated bad debts to initially be marginally under 1% of gross OPEX and that this percentage should decline slightly over the regulatory period. The information was presented in graphical form and no quantitative conclusions were provided.

54 Project Vision, Report for the Third Regulatory Reset Application of NGCP, Section 3, Working Capital. Pricewaterhouse Coopers Financial Advisors.

55 Ibid, Section 3.2.1, p2 56 Review of allowance for bad debt component of forecast regulated operating and maintenance expenditure for third

regulatory period: Report to NGCP. London Economics Consulting Group, December 2009.


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5.18 ERC Analysis – Working Capital

5.18.1 The ERC accepts the conclusions of both the PwC FA and LECG reports. The lead–lag method is a well accepted approach to calculating the working capital requirement and has been used by the ERC in calculating the working capital requirements of DUs operating under PBR.

5.18.2 The ERC has reviewed the PwC FA report directly and does not accept the interpretation in Section 14.2.4 of Annex A of the Revenue Application that the 7.29% should be applied to gross OPEX. As discussed in paragraph 5.17.2 above, the PwC report is very clear that the working capital provision is to be applied to net OPEX, or to total OPEX less working capital.

5.18.3 The ERC’s allowed OPEX included bad debts and therefore represent gross or total OPEX. Hence, if working capital is 7.29% and bad debts is 1% the working capital percentage would be approximately 6.29% of total OPEX.

5.19 ERC Preliminary Findings on Working Capital

5.19.1 The ERC’s Preliminary Findings is that the Regulated Entity’s total working capital requirement shall be 6.29% of its allowed total OPEX in 2011. In order to provide the Regulated Entity with an incentive to progressively reduce its working capital requirements it has decided that the allowed working capital provision shall reduce by 0.1% in each succeeding year of the Third Regulatory Period. This Preliminary Findings, which is not inconsistent with the Final Decision for the Second Regulatory Period57, is shown in Table 5.14.

Table 5.14: ERC Preliminary Findings – Working Capital (PhP million)

2011 2012 2013 2014 2015 Total

Approved OPEX Forecast (nominal)1 5,945.42 6,653.89 6,908.43 8,027.62 7,769.74

Working capital percentage 6.29% 6.19% 5.99% 5.89% 5.79%

Approved working capital provision (nominal) 373.97 411.88 413.81 472.83 449.87

Working capital provision (real) 358.55 379.71 366.82 403.01 364.84 1,872.93 Note 1: Includes OPEX for residual subtransmission assets.

5.20 ERC Preliminary Findings - Return on Asset Base

5.20.1 The ERC has used its regulatory revenue model to calculate the return on the asset base. This calculation is based on the opening asset base derived from a roll forward of the SKM valuation, as summarized in Table 5.7 and using a WACC of 13.63%, derived using the methodology explained in Section 5.16 and, more specifically, using the data shown in Table 5.12. The return on asset base allowed in this Preliminary Findings is shown in Table 5.15, where it is also compared with the forecast in the Revenue Application.

57 2006 Final Determination, Table 5.20.


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Table 5.15: ERC Preliminary Findings on Return on Asset Base (PhP million)

2011 2012 2013 2014 2015 Total Revenue Application (nominal) 38,691.00 42,221.10 44,373.30 45,478.30 45,593.60

Revenue Application (real) 37,095.88 38,923.50 39,334.24 38,763.22 36,975.74 191,092.58 ERC Preliminary Findings(nominal) 23,428.36 24,370.84 25,061.29 25,321.20 25,138.13

ERC Preliminary Findings (real) 22,462.47 22,467.40 22,215.31 21,582.41 20,386.65 109,114.25

5.21 Other Taxes

5.21.1 The Regulated Entity’s forecast other taxes, for which it seeks recovery within the MAR is shown in Table 5.16

Table 5.16: Revenue Application Forecast for Other Taxes (PhP million, nominal)

2011 2012 2013 2014 2015

Licenses 26.00 27.00 28.00 29.00 30.00

Real property taxes 30.00 31.00 32.00 34.00 35.00

Total 57.00 59.00 61.00 64.00 67.00 Source: Supplemental Report, Figure 29.

5.22 ERC Analysis – Other Taxes

5.22.1 RA 9557 has had a significant impact on the Regulated Entity’s tax liability. Apart from replacing NGCP’s income tax liability with a 3% national franchise tax, it has also exempt NGCP from other local and national taxes, which the notable exception of real property tax. Furthermore, it has exempt NGCP from charging VAT on the value of its invoices and passing VAT payments through the Bureau of Internal Revenue (BIR). However, the BIR has confirmed that NGCP is still liable to pay VAT on its inputs, which means that, from a customer perspective, the relief provided by the VAT exemption granted under RA 9557 is only partial.

5.22.2 In the Revenue Application, the Regulated Entity has provided no information on the license component of its forecast tax expenditure. There is no information on what licenses it is claiming for or how the forecast license fees were derived. Furthermore, as licenses were not separately identified in the discussion on taxes in Chapter 4 of Annex A of the Revenue Application, the ERC must assume that any license fees paid during the Second Regulatory Period were included in the actual OPEX spend. This being the case, license fees would have been included in the base OPEX that formed the key input to the derivation of ERC’s allowed OPEX. Hence, the ERC concludes that license fees are already included in the allowed OPEX forecast and should not be treated separately as a tax.

5.22.3 The real property tax forecast in Table 5.16 represents an average annual expenditure of PhP28.61 million, which is a 69% real increase on the real property taxes paid during the Second Regulatory Period. No justification has been provided for this substantial increase. The ERC has therefore decided to


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limit the real increase in real property taxes to 20%, which should be sufficient to cover the additional taxation on new property purchased or constructed over the Third Regulatory Period.

5.22.4 In its Revenue Application, the Regulated Entity has included the VAT that it must now pay on its inputs as a component of its forecast CAPEX and OPEX. While this approach presents few problems with respect to OPEX, the capitalization of VAT paid on CAPEX inputs will create issues with regard to the asset valuation for the Fourth Regulatory Period. If VAT paid during the Third Regulatory Period is capitalized, a portion of the asset base as it exists at the time of the next reset will have been constructed with VAT inclusive costs while the costs incurred in constructing the bulk of the asset base would not have incurred VAT. If the replacement cost revaluation of the full asset base undertaken for the reset is VAT inclusive, then the Regulated Entity will receive a windfall gain. On the other hand, if the revaluation is VAT exclusive, than the Regulated Entity must carry a windfall loss. Adjusting the revenue requirement to properly offset these windfall gains or losses will be problematic.

5.22.5 This problem will be avoided if asset valuations and CAPEX forecasts continue to be on a VAT exclusive basis and VAT paid on inputs is accounted for as a separate tax. From a practical perspective this should create few problems. Supplier invoices currently show the VAT component as a separate amount. The burden on customers will increase in the short term but ERC analysis shows that over time customers will actually pay less under this accounting approach58. Further, as VAT on CAPEX inputs is currently not capitalized, any burden on customers will still be less than currently exists.

5.23 ERC Preliminary Findings – Other Taxes

5.23.1 In this Draft Determination, the allowed CAPEX and OPEX for the Third Regulatory Period excludes VAT. The estimated VAT payable on this allowed expenditure is shown in Table 5.17 and is included in the other taxes component of the ARR.

5.23.2 The ERC’s Preliminary Findings on the other taxes to be included in the ARR for the Third Regulatory Period is shown in Table 5.17

Table 5.17: ERC Preliminary Findings on Other Taxes (PhP million, real 2010)

2011 2012 2013 2014 2015 Total

Licenses - - - - - -

Real Property Taxes 20.29 20.29 20.29 20.29 20.29 101.45

VAT on OPEX – RAB assets 349.74 350.66 336.41 393.58 332.79 1,763.17

VAT on OPEX – Residual subtransmission assets 17.55 17.78 17.88 20.17 17.96 91.34

VAT on CAPEX – RAB asset 508.64 422.95 316.47 211.67 119.14 1,578.87

VAT on CAPEX – Residual subtransmission assets 18.96 13.08 12.01 11.48 9.18 64.72

Total 915.18 824.76 703.06 657.19 499.36 3,599.55

58 This is because customers will not be required to pay the regulated return on the capitalized VAT.


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5.24 National Franchise Tax

5.24.1 Under RA 9511, NGCP is required to pay a national franchise tax of 3% on all revenues in lieu of income tax. As the amount of tax payable is a fixed proportion of revenue, and therefore outside NGCP’s control, the ERC has decided not to include the national franchise tax in the MAR. The ERC will permit NGCP to recover this tax by imposing a surcharge on all customer invoices. This surcharge must equal the amount of the national franchise tax that NGCP is required to pay in respect of the revenue received from that invoice.

5.25 Force Majeure Events

5.25.1 The Revenue Application (as amended by the Supplemental Report) includes claims for recovery of accelerated depreciation for assets damaged by the events shown in Table 5.18, which the Regulated Entity argues are force majeure events covered by Article X of the RTWR. Reimbursement is sought by adding the amount claimed to the MAR for 2011.

Table 5.18: Force Majeure Event Claims Event Date of Occurrence Accelerated Depreciation

Claimed ERC Case Reference

Typhoons Milenyo, Paeng, Reming and Seniang

Milenyo – Sept 2006 Reming – Nov 2006 Seniang – Dec 2006 Paeng – Jan 2007

PhP 284.08 million 2007-148-RC

Typhoons Cosme and Frank. Sabotaged towers 24, 41, 46-48 and 222 in Mindanao

Cosme – May 2008 Frank – June 2008 Sabotage – Sep-Nov 2008

PhP 219.67 million in the revenue application, amended to PhP 34.93 million in the Supplemental Report

2009-049-RC dated July 13 2009.

Sabotaged towers 52, and 31 in Mindanao

Feb-Mar 2009 2009-161-RC dated Nov 16, 2009

Transformer fire damage at Dolores substation

- PhP 51.94 million -

5.26 ERC Analysis – Force Majeure Events

5.26.1 No disallowance yet considering that two of the above cases are still being heard by the Commission. The provision of PhP 284.08 million in respect of ERC Case No. 2007-148-RC is consistent with the ERC decision on this case, issued on January 7, 2009. In this decision the ERC set a precedent allowing for the recovery of accelerated depreciation in certain circumstances where assets are damaged by force majeure events before the end of their economic life.

5.26.2 ERC Case No 2009-049 RC has still to be resolved. In its filing NGCP notes that some assets affected by the force majeure events were completely destroyed and that the Regulated Entity should therefore be entitled to recover accelerated depreciation. The filing does not specify the amount claimed (possibly because this would depend on the outcome of the SKM valuation, which would not have been available at the time of the filing) but states that it planned to include the claim in the Revenue Application.

5.26.3 Clause 10.2.1 of the RTWR requires a force majeure event claim to be submitted within 12 months of the event occurring. It seems that NGCP has not met this deadline in respect of Typhoons Cosme and Frank.


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5.26.4 ERC Case No. 2009-161 RC was in respect of the sabotage of towers 51 and 32 in Mindanao was filed at the same time as the Revenue Application. This filing makes no reference to accelerated depreciation.

5.26.5 The Regulated Entity has submitted no explanation for the reduction in the amount of accelerated depreciation claimed in respect of the typhoon and sabotage damage covered by ERC Case Nos. 2009-049 RC and 2009-161 RC. In addition no information has been provided to support the claim for accelerated depreciation in respect of fire damage to the Dolores substation transformers and no case has been filed in respect of this event.

5.26.6 Article X of the RTWR provides for the recovery of costs in respect of a force majeure event only through the submission of a Force Majeure Event Claim, which allows the impact of the event and the circumstances of the claim to be examined in detail on its merits. There is no provision for this process to be bypassed by having some of all of the costs associated with any claim allowed as part of a reset process.

5.27 ERC Preliminary Findings – Force Majeure Events

5.27.1 No disallowance yet considering that two of the above cases are still being heard by the Commission. The provision of PhP 284.08 million in respect of ERC Case No. 2007-148-RC is consistent with the ERC decision on this case, issued on January 7, 2009. In this decision the ERC set a precedent allowing for the recovery of accelerated depreciation in certain circumstances where assets are damaged by force majeure events before the end of their economic life.

5.28 Net Efficiency Adjustments

5.28.1 Article IX of the RTWR provides for the MAR for the Third Regulatory Period to incorporate efficiency adjustments that are designed to ensure that the Regulated Entity has an incentive to achieve reductions in controllable costs above those implied by the CAPEX and OPEX forecasts approved by the ERC in its 2006 Final Determination. As explained in the Position Paper, the Net Capital Efficiency Adjustment (CEA) and the Net Operating and Maintenance Efficiency Adjustment (OEA) pertaining to each year of the regulatory period is calculated using the following process:

• The forecast CAPEX and OPEX for that year, as approved by the ERC in the 2006 Final Determination, are adjusted to take account of costs that were not foreseen at the time of the Final Determination and that were outside the control of the Regulated Entity. This adjustment can be positive or negative.

• The CEA is the difference between the actual CAPEX and the adjusted CAPEX with this difference being multiplied by the WACC. The CEA is positive if the actual CAPEX is less than the adjusted CAPEX.

• The OEA is calculated differently and, apart from 2006, the adjustment is based on the improvements in efficiency from the previous year. If the actual increment in OPEX over the previous year is less than the corresponding increment in the adjusted OPEX forecast, the Regulated


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Entity will receive a positive OEA for that year equal to the difference in the two incremental expenditures59. For 2006, the OEA is equal to the difference between the actual and forecast OPEX.

• Both the CEA and the OEA are retained by the Regulated Entity for a period of five years following the year to which the adjustment relates.

5.29 ERC Preliminary Findings on Net Efficiency Adjustments

5.29.1 The derivations of the CEA and the OEA applied to the MAR for the Third Regulatory Period are shown in Tables 5.19 and 5.20.

Table 5.19: Derivation of Approved CEA (PhP million) 2006 2007 2008 2009 2010

WACC 15.88% 15.88% 15.88% 15.88% 15.88%

Approved CAPEX forecast (nominal) 9,923.40 11,286.90 7,370.80 4,393.00 3,920.20

Adjusted CAPEX forecast (nominal) 10,779.06 11,018.50 7,779.10 5,252.17 8,344.20

Actual and budgeted CAPEX (nominal) 6,893.70 8,560.30 7,384.70 8,747.40 18,871.70

CEA 2006 (nominal) - 617.00 617.00 617.00 617.00

CEA 2007 (nominal) - - 390.36 390.36 390.36

CEA 2008 (nominal) - - - 62.63 62.63

CEA 2009 (nominal) - - - - (555.04)

2011 2012 2013 2014 2015

CEA 2006 (nominal) 617.00 - - - -

CEA 2007 (nominal) 390.36 390.36 - - -

CEA 2008 (nominal) 62.63 62.63 62.63 - -

CEA 2009 (nominal) (555.04) (555.04) (555.04) (555.04) -

CEA 2010 (nominal) (1,671.77) (1,671.77) (1,671.77) (1,671.77) (1,671.77)

Total CEA (nominal) (1,156.82) (1,773.82) (2,164.18) (2,226,81) (1,671.77)

Total CEA (real 2010) (1,109.13) (1,635.28) (1,918.01) (1,898.01) (1,355.78)

59 See Clause 9.2.3 of the RTWR for the formula used.


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Table 5.20: Derivation of Approved OEA (PhP million) 2006 2007 2008 2009 2010

Approved OPEX forecast (nominal) 5,068.90 5,298.10 5,714.70 5,801.00 5,935.10

Adjusted OPEX forecast (nominal) 4,836.20 4,807.20 5,924.50 5,500.10 6,656.60

Add permit and supervision fees – Case 2005-041-RC 74.53 84.65 55.28 32.95 29.40

Add permit and supervision fees – Case 2007-148-RC - - - 13.88 -

Revised adjusted OPEX forecast (nominal) 4,910.73 4,891.85 5,979.78 5,546.93 6,686.00

Actual and budgeted OPEX (nominal) 3,466.40 4,006.10 4,922.40 5,726.30 7,483.80

Increment in revised adjusted OPEX forecast (nominal) - (18.87) 1,087.93 (432.85) 1,139.07

Increment in actual OPEX (nominal) - 539.70 916.30 803.90 1,757.50

OEA 2006 (nominal) - 1,444.33 1,444.33 1,444.33 1,444.33

OEA 2007 (nominal) - - (558.57) (558.57) (558.57)

OEA 2008 (nominal) - - - 171.63 171.63

OEA 2009 (nominal) - - - - (1,236.75)

2011 2012 2013 2014 2015

OEA 2006 (nominal) 1,444.33 - - - -

OEA 2007 (nominal) (558.57) (558.57) - - -

OEA 2008 (nominal) 171.63 171.63 171.63 - -

OEA 2009 (nominal) (1,236.75) (1,236.75) (1,236.75) (1,236.75) -

OEA 2010 (nominal) (618.43) (618.43) (618.43) (618.43) (618.43)

Total OEA (nominal) (797.80) (2,242.12) (1,683.55) (1,855.18) (618.43)

Total OEA (real 2010) (764.91) (2,067.01) (1,492.37) (1,581.25) (501.54)


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6. CALCULATION OF ALLOWED REVENUE

6.1 Unsmoothed Revenue - Real

6.1.1 Based on the ERC preliminary findings made in this Draft Determination, the MAR for the Third Regulatory Period, expressed in real 2010 PhP is shown in Table 6.1. The amount shown for 2010 is a revenue shortfall from the Second Regulatory Period that needs to be taken into account during the smoothing process. This can be compared with the MAR requested by the Regulated Entity in the Revenue Application, which is shown in Table 6.2.

Table 6.1: ERC Preliminary Findings on Maximum Allowed Revenue for Third Regulatory Period (PhP million, real 2010)

2010 2011 2012 2013 2014 2015

Second Regulatory Period revenue shortfall (Table 3.11) 15,044.42 - - - - -

Recovery of income tax provision (Table 3.14) (12,839.01) - - - -

Adjustment for other taxes Table 3.16) 1,109.08 - - - - -

OPEX (Table 5.3) - 5,700.31 6,134.20 6,123.90 6,842.30 6,301.14


Return on capital (Table 5.15) - 22,462.47 22,467.40 22,215.32 21,582.41 20,386.65

Real property taxes and VAT (Table 5.17) - 915.18 824.76 703.06 657.19 499.36



Total ARR (real) 3,314.49 33,822.85 32,176.94 31,844.19 31,424.34 30,920.58

Table 6.2: Revenue Application – Maximum Allowed Revenue for Third Regulatory Period (PhP million, real 2010)

2010 2011 2012 2013 2014 2015


Recovery of income tax provision (Table 3.14) (8,142.00) - - - - -

Adjustment for other taxes (1,036.00) - - - - -

OPEX - 7,640.08 7,069.01 6,995.25 7,424.61 7,013.97



Real property taxes and VAT - 1,321.19 1,413.73 1,508.90 1,610.51 1,701.20


Net efficiency adjustment - 145.83 140.22 134.83 129.64 123.35

Total ARR (real) 20,622.00 53,333.08 54,711.72 55,032.81 55,044.98 52,334.09

6.1.2 Table 6.3 compares the total revenue allowed by this Draft Determination with that sought by the Regulated Entity in its Revenue Application for the period 2010-2015 and provides a brief summary of the reasons for the differences.


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Table 6.3: Comparison of ERC’s Maximum Allowed Revenue with Revenue Application (PhP million, real 2010)

Total Revenue (2010-15)

Variance Remarks Revenue

Application Preliminary

Findings

Second Regulatory Period revenue shortfall (Table 3.11) 29,800.00 15,044.42 (49.5%)

The ERC limited recovery of revenues as a consequence of actual demand being lower than the forecast. Recovery of revenues relating to the P0 adjustment and the PIS was allowed.

Recovery of income tax provision (Table 3.14) (8,142.00) (12,839.41) (57.7%)

The ERC did not allow recovery of the income tax provision relating to the disallowed revenue recovery.

Adjustment for other taxes (1,036.00) 1,109.08

The ERC did not allow recovery of the excess provision for other taxes in 2006-08 as this is not provided for in the RTWR.

OPEX 36,142.92 31,101.86 (13.9%)

ERC accepted the NCL recommendation. The Draft Determination includes OPEX relating to residual subtransmission assets.

Return of capital (depreciation) 34,508.77 30,424.54 (11.8%)

Return on capital 191,092.58 109,114.25 (42.9%)

The allowed WACC was 13.63% compared to 19% in the Revenue Application. Other factors included reductions in the CAPEX forecast and the disallowance of a CWIP factor, consistent with the regulatory approach in other jurisdications1. CWIP was included in the RAB.

Other taxes 7,555.53 3,599.55 (52.4%)

Includes VAT but excludes the 3% national franchise tax, which the ERC has decided will be recovered outside the MAR.

Force majeure adjustment 483.03 272.37 (43.6%) Allowed under ERC Case 2007-148-RC only.

Net efficiency adjustment 673.87 (14,322.59)

The ERC accepted NCL’s recommendation that many of the proposed adjustments to the 2006 Final Determination forecasts not be accepted.

Total 291,078.69 163,504.07 (43.8%)

CAPEX2 80,779.97 42,635.94 (47.2%)

The ERC has accepted NCL’s recommendations on CAPEX reductions. The Draft Determination includes CAPEX on residual subtransmission assets but excludes ROW and other land related CAPEX, which the ERC has decided will be recovered during the Fourth Regulatory Period following an ex post prudency review

Note 1: While the RTWR provides for a CWIP factor, this requires CAPEX to be presented on an “as commissioned” rather than “as spent” basis.

Note 2: Provided for information only as CAPEX is not a MAR building block.


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6.1.3 There is some variation between the scope of the MAR approved by this draft determination and the scope that formed the basis for the Revenue Application. In particular:

• The ERC’s allowed OPEX and CAPEX include expenditures on residual subtransmission assets. Should the ERC decide not to abolish the residual subtransmission charge, as currently provided for in the draft OATS Rules, these forecasts will need to be adjusted;

• The ERC’s allowed CAPEX excludes all land related expenditures, including the settlement of ROW claims by both TransCo and NGCP. The basic issue is the unpredictability of both the magnitude and timing of ROW settlements and the consequent difficulty in validating the Regulated Entity’s forecasts. The ERC has decided that the Regulated Entity can recover efficient land and ROW costs incurred, together with the appropriate return, during the Fourth Regulatory Period, following an ex-post prudency review of these expenditures.

• The approved MAR does not include the 3% national franchise tax, as the ERC has decided that this should be added directly to the ERC’s customer invoices for the provision of regulated services.

6.1.4 Figure 6.1 compares the ERC’s Preliminary Findings on the unsmoothed ARR for the Third Regulatory Period with the Revenue Application forecast. There is also a comparison with the unsmoothed MAR for the Second Regulatory Period as allowed in the 2006 Final Determination, as well as the constrained MAR for 2010, as determined by the ERC, after taking into account the impact of the side constraints. The actual collections shown in the figure are taken from the rate cases and are therefore collection to the end of August, except for the 2010 number, which is the constrained MAR allowed by the ERC in the 2010 rate case. This amount could well be high since the Regulated Entity was not able to fully recover the constrained MAR allowed by the ERC in any earlier year of the Second Regulatory Period.

Figure 6.1: Comparison of ERC’s Preliminary Findings on MAR with Revenue Application and 2006 Final Determination (PhP million, real 2010)


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6.2 Inflation Assumptions

6.2.1 In converting real to nominal PhP the ERC has used change in the Philippines CPI forecast by the EIU as at February 2010. This is shown in Table 6.4

Table 6.4: Assumed Change in Philippine CPI 2011 2012 2013 2014 2015

Change in Philippines CPI 4.30% 4.00% 4.00% 4.00% 5.10%

6.3 Unsmoothed Revenue - Nominal

6.3.1 The ERC’s preliminary findings on the Regulated Entity’s MAR for the Third Regulatory Period, expressed in nominal PhP, is shown in Table 6.5. A comparison of this Preliminary Findings with the Regulated Entity’s forecast in the Revenue Application is provided in Figure 6.2. In the ERC approved MAR the under-recoveries from the Second Regulatory Period have been absorbed into the MAR for the Third Regulatory Period in a manner that ensures that the NPV of the raw and approved revenues streams are the same. This analysis is shown in Table 6.6. Figure 6.3 shows the approved MAR broken down into its different building block components.

Table 6.5: ERC Preliminary Findings on Maximum Allowed Revenue for Third Regulatory Period (PhP million, nominal)

2010 2011 2012 2013 2014 2015


Recovery of income tax provision (Table 3.14) (12,839.01) - - - - -

Adjustment for other taxes 1,109.08 - - - - -

OPEX - 5,945.42 6,653.89 6,908.43 8,027.62 7,769.74



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Real property taxes and VAT - 954.53 894.63 793.14 771.04 615.75



Raw MAR 3,314.49 35,277.23 34,902.98 35,923.71 36,868.07 38,127.18

Adjustment for Second Regulatory Period under-recoveries

(3,314.49) 936.88 926.94 955.05 979.13 1,012.57

Approved MAR - 36,214.11 35,829.91 36,877.75 37,847.20 39,139.75

Table 6.6: Derivation of Approved MAR (PhP million, nominal) 2010 2011 2012 2013 2014 2015

Raw ARR 3,314.49 35,277.23 34,902.98 35,923.71 36,868.07 38,127.18

Raw NPV1 124,803.84 - - - - -

Required NPV2 128,118.33 - - - - -

Approved unsmoothed ARR3 - 36,214.11 35,829.91 36,877.75 37,847.20 39,139.75 Note 1: The NPV of the 2011-15 elements of the raw MAR. Note 2: Sum of Raw NPV and 2010 component of required NPV. Note 3: The 2011-14 elements of the raw MAR have been escalated by the ratio of the required NPV to the

raw NPV.

Figure 6.2: ERC Preliminary Findings compared with Revenue Application (PhP million, nominal)

Figure 6.3: Components of Approved Unsmoothed Maximum Annual Revenue (PhP million, nominal)


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6.4 Side Constraints

6.4.1 The ERC sees no basis for changing the current standard side constraint of CPI+2%.

6.5 Revenue Smoothing

6.5.1 Revenue smoothing is undertaken to reduce the likelihood of price shocks to customers and of revenue shocks to the Regulated Entity. The process for smoothing revenue is described in Section 5.13 of the RTWR. The objective of the process is to achieve a revenue path whereby the net present value of the smoothed revenue path is equal to the net present value of the MAR as at the end of 2010, including the value of any revenue adjustments that are shown as being applied in 2010.

6.5.2 The ERC has identified a minor inconsistency between the formulae in clauses 5.13.5(a) and 5.13.5(b) of the RTWR. This inconsistency would be resolved if the parameter Inflationt in the formula in Clause 5.13.5(b) was changed to Inflationt-1. This adjustment is consistent with the real life situation in that, where prices are set at the beginning of the year, they should be adjusted in accordance with the previous year’s inflation. It is also consistent with the application of the price control formula in Clause 5.2.360. The formula in clause 5.13.4 should also be changed to be consistent with this change.

6.5.3 In applying the smoothing formulae, the ERC has adopted the corrected approach. However this has not resulted in material change to the smoothed

60 While this is not apparent from the formula in clause 5.2.3, the term CWIt is mathematically

defined to reflect price and exchange rate movements in year t-1.


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revenue path as the forecast inflation rates remain relatively constant over the Second Regulatory Period.

6.5.4 The ERC then applied the smoothing formulae described in Section 5.13 to the approved MAR. The starting point for the smoothing process is the constrained MAR for 2010, which the ERC determined to be PhP 44,991.45 million61. The process involves applying a P0 adjustment to the 2010 constrained MAR and then applying the formula in Clause 5.13.5 of the RTWR to this adjusted 2010 MAR62. The object of the analysis is to obtain a smoothed revenue stream with an NPV equal to the required NPV (as calculated in the analysis shown in Table 6.6). Hence if P0 is increased, the adjusted 2010 MAR (given by the expression MAR2010-P0) will reduce and the X factor must also reduce to offset this. It is thus possible to determine a number of possible smoothed revenue paths, all of which will return the regulated entity the required total revenue in NPV terms over the regulatory period.

6.5.5 A range of possible smoothed revenue paths, all of which meet the criteria described in paragraph 6.5.4, is shown in Table 6.7. These revenue paths are shown diagrammatically in Figure 6.4. The constrained 2010 MAR is also shown in Figure 6.4 for comparison.

Table 6.7: Possible Smoothed Revenue Paths (PhP million, nominal)

P0 X SMAR

2011 2012 2013 2014 2015

0 11% 41,738.57 38,929.56 36,192.81 33,648.46 31,282.97

7,968.00 4% 36,949.40 37,060.25 37,060.25 37,060.25 37,060.25

11,800.00 0% 34,452.73 35,934.19 37,371.56 38,866.42 40,421.08

Unsmoothed ARR 36,214.16 35,830.07 36,877.89 37,847.42 39,139.83

61 ERC Case No 2009-160RC, Order dated January 19,2010. 62 As shown in clause 5.13.4 of the RTWR the adjusted 2010 MAR is found from the

expression MAR2010-P0.


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Figure 6.4: Possible Smoothed Revenue Paths (PhP million, nominal)

6.5.6 It can be seen from Figure 6.4 that the P0 and X factors are interrelated. A low P0 factor will mean that the revenue in the first year of the regulatory period is high, leaving room for rate reductions as the regulatory period progresses. On the other hand, a high P0 factor will lower the revenue requirement in the first year of the regulatory period but it will also mean a lower X factor, meaning revenues later in the regulatory period need to be higher.

6.5.7 The ERC seeks feedback from stakeholders on the appropriate revenue path. It may be that an X factor of 4% is appropriate and this could mean that revenues (and prices) will stay relatively constant in nominal terms over the regulatory period63. The ERC notes that if the X factor is set at 0% it may be desirable to increase the existing CPI+2% side constraint, as there needs to be a margin between the X factor and the side constraint to accommodate load forecasting errors. The ERC would therefore prefer an X factor of at least 2%. This would result in a revenue path of CPI-2% and provide a 4% buffer between the revenue path and the side constraint.

6.6 Estimated Power Delivery Service Rates

6.6.1 Table 6.8 and Figure 6.5 provide an estimate of the average power delivery service (PDS) rates for the Third Regulatory Period, based on the ERC’s approved unsmoothed MAR, and compares these with the current PDS rates on each of the three grids. In developing this estimate, the ERC has reduced the billing determinant provided by the Regulated Entity in Section 18.3.3 of Annex A of the Revenue Application to account for the reduced load forecast in Table 4.1.

63 The actual change in prices will depend on the extent to which the actual CPI varies from the assumptions made in this Draft Determination and also in the rate of growth in electricity demand on the network over the third regulatory period.


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Table 6.8: Estimated Power Delivery Service Rates 2010 2011 2012 2013 2014 2015

Approved unsmoothed MAR (PhP million, nominal) - 36,214.11 35,829.91 36,877.75 37,847.20 39,139.75

Assumed billing determinant (MW/month) - 120,848 123,811 126,700 129,274 131,830

Estimated average PDS rates (PhP/kw/month, nominal) - 299.67 289.39 291.06 292.77 296.89

Current PDS rate – Luzon (PhP/kW/month, nominal) 355.94 - - - - -

Current PDS rate – Visayas (PhP/kW/month, nominal) 334.51 - - - - -

Current PDS rate – Mindanao (PhP/kW/month, nominal) 330.97 - - - - -

Revenue Application PDS rates (PhP/kW/month, nominal)1 - 401.81 431.71 463.90 499.63 543.37

Note 1: Revenue Application, Annex A, Section 18.4

Figure 6.5: Estimated Power Delivery Service Rates (PhP/kW/month, nominal)


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7. OTHER ISSUES

7.1 Network Planning

7.1.1 The Regulated Entity’s approach to grid planning appears not to be in the best interests of the consumer as it does not ensure the minimization of the total electricity costs that consumers must pay.

7.1.2 It was apparent from the CAPEX forecast submitted with the Revenue Application, and the information provided to support the various projects in the forecast, that the Regulated Entity’s approach to grid planning is little changed from the approach taken before the restructuring of the National Power Corporation and the introduction of WESM. Projects were prioritized purely on the basis of expected energy not served (EENS), notwithstanding the fact that Clause 5.2.1.1 of the Grid Code requires the grid owner to identify congestion problems that may result in increased outages or raise the cost of service significantly (ERC emphasis).

7.1.3 Severe congestion problems routinely occur on the grid and, while not causing an outage, are managed through the dispatch of more expensive out of merit generation. While this has no impact on the Regulated Entity, it raises the cost of electricity to consumers. However, the information provided to the ERC in support of the CAPEX forecast showed no evidence that the Regulated Entity had discussed its grid planning priorities with the Philippines Electricity Market Corporation (PEMC) or with consumer representatives. There was little evidence in any of the information provided to the ERC that the need to improve the operation of WESM was one of the factors taken into account when planning the development of the grid.

7.1.4 The Regulated Entity’s grid planning criteria is based on a requirement to design the network for the grid to avoid loss of load in the event of a single network element outage under an extreme generation dispatch scenario. For example, one dispatch scenario used for the Luzon grid is the maximum south – dry scenario where all generators in the south part of the network are assumed to be simultaneously at their maximum dispatch. It is not clear that this dispatch scenario is realistic as it implies that lower cost generation north of Manila is assumed not be dispatched.

7.1.5 The use of deterministic planning criteria based on extreme generation dispatch criteria can lead to the sub-optimal investment planning decisions. For example, such an approach is likely favor a project to address a low probability loss of load situation under the extreme dispatch scenario in preference to a project intended to alleviate a serious but commonly occurring grid constraint. This is because the grid constraint does not result in a loss of load. Such a planning decision would not be in the interest of consumers, who must regularly bear the higher cost of the generation that is routinely dispatched to avoid the grid constraint.

7.1.6 In a sense, the low probability loss of load scenario described above is an n-2 contingency as it requires both a line or transformer outage and the network to be working well outside its normal operating parameters, presumably as a result of some other extreme situation.


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7.1.7 Due to these concerns, the ERC requires the Regulated Entity to formally review its approach to grid planning in order to develop planning criteria that better support the operation of WESM and the objective of minimizing the total cost of electricity to consumers. This planning review must include meaningful consultation with industry stakeholders including PEMC, generators, distributors and consumers.

7.1.8 Outcomes of the review are to be:

• a formal process for the active and meaningful participation of a wide range of industry stakeholders in planning grid development;

• the introduction of modern economic analysis tools in the assessment and prioritization of alternative projects. Net economic benefit, rather than EENS, is now the standard international measure for electricity industry planning. It is a measure that not only allows different grid development projects to be compared and prioritized but also allows grid projects to be evaluated against non-grid solutions, such as the development of new generation.

• the introduction of probability assessments into the planning and assessment process. This would allow the benefits of projects to mitigate adverse impacts on stakeholders that arise during the course of normal grid operation to be directly compared with alternative projects that address higher impact scenarios that have a low probability of arising.

7.1.9 The development of the transmission grid is critical to the efficient development of the broader industry. The Regulated Entity is therefore directed to provide the ERC with a copy of the review findings and advise the ERC of the actions that it intends to take in response to these findings.

7.2 Systems Operations and Ancillary Services

7.2.1 NGCP has submitted its strategy on addressing the present ancillary services deficiency. The strategy was brief and contained few specifics. There was no analysis of the quantity of each of the different types of ancillary service required by each grid and no procurement targets. Strategies to address current shortages were noted only in very high level, non-specific terms. It provided little evidence that NGCP has a meaningful plan in place to actively address the current shortages of ancillary services.

7.2.2 The ERC is therefore proposing to extend the PIS described in Section 4.7 to include an indicator related to the procurement of ancillary services. To this end, it seeks input from NGCP and other industry stakeholders on the definition and possible parameters64 of a suitable indictor.

7.2.3 Comments on the development and implementation of a suitable PIS measure should be provided by stakeholders at the same time as other written comments on this Draft Determination. The ERC will also develop its own proposal, which it will release during the public consultation hearings on this Draft Determination. Stakeholders will then have an opportunity to provide

64 Parameters include target performance, dead band, collar and cap.


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written comments on the ERC proposal. Should the ERC decide to implement and additional performance indicator, full details will be provided in the Final Determination.

7.3 Reopening Threshold

7.3.1 In Section 20.3 of Annex A of the Revenue Application, the Regulated Entity submitted that there is a strong case for revising the thresholds for a reopening of the MAR specified in Article XII of the RTWR. This is not an issue for this Draft Determination. Should the Regulated Entity wish to pursue this matter, it should submit a Petition for Rule Making to amend the RTWR in accordance with the procedures of the ERC.

Pasig City, July 15, 2010.

ZENAIDA G. CRUZ-DUCUT Chairperson

ALEJANDRO Z. BARIN RAUF A. TAN Commissioner Commissioner

MARIA TERESA A.R. CASTAÑEDA JOSE C. REYES Commissioner Commissioner

GB/ajmo/FGB

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APPENDIX A

REVENUE CARRYOVER ANALYSIS

Table A1 shows the nominal SMAR from the 2006 Final Determination, derived using the price control formula in Section 4.1 of the RTWR. The term CWIt is taken from the assumptions in the 2006 Final Determination. All analysis in this section is similar to that undertaken by the ERC during the annual rate setting process.

Table A.1: 2006 Final Determination SMAR (PhP million, nominal) Final Determination Pricing

2005 2006 2007 2008 2009 2010

MARt-1 - 35,611.60 37,249.73 38,590.72 39,709.86

P0 - - - -

CWIt 7.30% 5.60% 4.60% 3.90% 4.30%

X 0.01 0.01 0.01 0.01 0.01

MRRt 35,611.60 37,249.73 38,590.72 39,709.86 41,020.28

Manila Reference Rate

Kt

Related Business Revenue

Portion of RBR assigned to revenue cap

RBRt

PIS

MARRY 35,611.60 37,249.73 38,590.72 39,709.86 41,020.28

Collection to end August

Under(over) recovery

SMAR Table A2 adjusts the analysis in Table A1 to reflect the actual movements CWIt experienced during the Second Regulatory Period. The values of CWIt are taken from the ERC’s annual rate case decisions. The table also includes the related business revenue, RBRt, as determined by the ERC in its rate case decisions.

Table A.2: Adjusted SMAR (PhP million, nominal) 2005 2006 2007 2008 2009 2010

MARt-1 - 35,611.60 37,723.37 36,372.87 36,226.22

P0 - - - -

CWIt 0.0788 0.0693 -0.0258 0.005968 0.085411

X 0.01 0.01 0.01 0.01 0.01

MRRt 35,611.60 37,723.37 36,372.87 36,226.22 38,958.07

Manila Reference Rate

Kt

Related Business Revenue - 7.1 5 254.58 266.11

Portion of RBR assigned to revenue cap 0.5 0.50 0.5 1.00 1.00

RBRt - 3.55 2.50 254.58 266.11

PIS

MARRY 35,611.60 37,719.82 36,370.37 35,971.64 38,691.96

Collection to end August

Under(over) recovery In Table A3, the SMAR for each year of the regulatory period is adjusted to carry forward accumulated under-recoveries from earlier years. As the P0 adjustment or PIS rewards are not included in the analysis the total under-recovery is due only to the impact of side constraints and the lower actual demand.

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Table A.3: Under-recoveries Due to Side Constraints and Low Demand (PhP million, nominal)

Inclusion of Under‐recoveries2005 2006 2007 2008 2009 2010

MARt-1 - 35,611.60 37,723.37 36,372.87 36,226.22

P0 - - - -

CWIt 0.0788 0.0693 -0.0258 0.005968 0.085411

X 0.01 0.01 0.01 0.01 0.01

MRRt 35,611.60 37,723.37 36,372.87 36,226.22 38,958.07

Manila Reference Rate 0.1019 0.0951 0.0890 0.08008 0.0767

Kt 1,317.91- 1,452.20- 10,274.01- 16,763.66- 19,803.73- 18,747.25-



RBRt - 3.55 2.50 254.58 266.11

PIS

MARRY 37,063.80 47,993.83 53,134.03 55,775.37 57,439.21

Collection to end August 27,682.00 32,600.20 34,798.60 38,363.60 44,991.45

Over (under) recovery 1,317.91- 9,381.80- 15,393.63- 18,335.43- 17,411.77- 12,447.76- In Table A4 the P0 adjustment is included in the analysis.

Table A.4 Under-recoveries Due to Low Demand and P0 Adjustment (PhP million, nominal)

2005 2006 2007 2008 2009 2010

MARt-1 - 35,611.60 37,723.37 36,372.87 36,226.22

P0 6,415.00- - - - -

CWIt 0.0788 0.0693 -0.0258 0.005968 0.085411

X 0.01 0.01 0.01 0.01 0.01

MRRt 35,611.60 37,723.37 36,372.87 36,226.22 38,958.07


Kt 1,397.91- 8,609.05- 18,111.47- 25,298.66- 29,022.21- 28,672.79-



RBRt - 3.55 2.50 254.58 266.11

PIS

MARRY 44,220.65 55,831.29 61,669.03 64,993.85 67,364.75


Under(over) recovery 7,812.91- 16,538.65- 23,231.09- 26,870.43- 26,630.25- 22,373.30- Finally, in Table A5, the PIS rewards are added in.

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Table A.5 Under-recoveries Due to Low Demand, P0 Adjustment and PIS Rewards (PhP million, nominal)

2005 2006 2007 2008 2009 2010

MARt-1 - 35,611.60 37,723.37 36,372.87 36,226.22

P0 6,415.00- - - - -

CWIt 0.0788 0.0693 -0.0258 0.005968 0.085411

X 0.01 0.01 0.01 0.01 0.01

MRRt 35,611.60 37,723.37 36,372.87 36,226.22 38,958.07


Kt 1,397.91- 8,609.05- 18,111.47- 25,689.61- 30,019.07- 30,106.07-



RBRt - 3.55 2.50 254.58 266.11

PIS 359 532 334.32 234

MARRY 44,220.65 56,190.29 62,591.98 66,325.03 69,032.03


Under(over) recovery 7,812.91- 16,538.65- 23,590.09- 27,793.38- 27,961.43- 24,040.58-

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APPENDIX B

BREAKDOWN OF ERC APPROVED CAPEX FORECAST

Table B.1: Breakdown of ERC Approved CAPEX Forecast 2011 2012 2013 2013 2015

Tx Lines - Buildings, civil works and establishment 417.99 139.16 18.88 38.15 37.30 Tx Lines - Towers and associated lines 3,658.05 4,620.39 2,670.73 1,668.19 1,292.46 Tx Lines - Poles and associated lines 344.60 314.33 558.72 101.24 167.13 Tx Lines - Underground cables 0.57 0.36 0.24 220.33 75.11 Tx Lines - Submarine cables - - - - - Tx Lines - Easements owned by the Regulated Entity 0.32 - - - - Tx Lines - Other 602.07 920.76 897.76 830.96 667.77 Tx Lines - Spares, spare parts and tools 321.03 222.13 234.55 234.02 256.21 Tx Lines - Land used for transmission lines - - - - - Tx Subst Comp - Buildings, civil works and establishment 1,323.67 733.45 509.91 325.96 105.44 Tx Subst Comp - Power T ransformers 1,792.63 2,655.08 2,347.21 1,247.74 349.71 Tx Subst Comp - Circuit breakers and Accessories 1,127.86 943.63 854.93 545.91 274.49 Tx Subst Comp - Instrument transformers 98.31 24.41 18.26 24.82 14.81 Tx Subst Comp - Protection and control equipment 874.38 691.36 476.24 210.88 160.70 Tx Subst Comp - Power compensation equipment eg reactors 225.18 189.72 138.38 305.54 60.40 Tx Subst Comp - Buswork, power and control cables 362.02 351.15 303.81 210.47 85.82 Tx Subst Comp - Other 835.39 729.86 569.41 292.44 92.57 Tx Subst Comp - Spares, spare parts and tools 461.80 408.19 338.49 282.03 128.26 Tx Subst Comp - Land owned but used for substations - - - - - Comms Plant - Buildings, civil works and establishment 0.02 - - 3.62 3.92 Comms Plant - Communications plant and infrastructure 171.83 181.19 118.17 51.03 42.14 Comms Plant - Fibre optic cables 47.28 11.34 2.21 15.65 7.16 Comms Plant - Fibre optic cable terminal equipment 5.90 32.81 18.17 17.09 8.28 Comms Plant - Ancillary infrastructure 0.13 0.02 0.01 0.02 0.05 Comms Plant - Other 23.73 61.05 40.67 27.20 13.89 Comms Plant - Spares, spare parts and tools - - - 2.15 0.62 Comms Plant - Land owned and used for communications plant - - - - - Sys Ops - Buildings, civil works and establishment 14.88 1.92 1.39 0.54 0.53 Sys Ops - Control room and control infrastructure 10.79 1.56 2.98 0.75 0.79 Sys Ops - Ancillary infrastructure 208.01 69.63 110.87 26.44 34.16 Sys Ops - Other 108.26 28.09 36.49 18.19 19.90 Sys Ops - Spares, spare parts and tools 9.58 2.07 2.15 1.14 1.33 Sys Ops - Land owned but used for system operations - - - - - Metering - Market meters 22.31 52.08 42.77 9.46 6.66 Metering - Meters which are not Market Meters, Connection Assets or Sub-transmission assets

125.91 106.33 108.66 118.95 113.99

Non-Network Assets - Computers, and office equipment 53.26 31.57 33.32 34.80 25.87 Non-Network Assets - Plant, tools, and equipment 342.71 49.24 34.67 133.11 25.21 Non-Network Assets - Furniture, fixtures, and fitt ings 33.22 13.80 14.02 11.45 17.76 Non-Network Assets - Commercial buildings 39.91 15.78 5.96 0.06 0.07 Non-Network Assets - Land owned but used for non-network assets covers all land value not previously attributed

- - - - -

Non-Network Assets - Other 92.32 14.36 8.80 5.28 6.72 Total (nominal) 13,755.89 13,616.83 10,518.84 7,015.61 4,097.24

0.959 0.922 0.886 0.852 0.811Total (real, 2010) 13,188.77 12,553.31 9,324.31 5,979.72 3,322.80

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APPENDIX C

BREAKDOWN OF OPENING RAB

Asset Category O DRCDec 10

Weighted Average Age

Weighted Average Asset Life

(a) Transmission Lines -Buildings, civil works and establishment 80.89 0.66 50

(a) Transmission Lines -Towers and associated lines 47,505.45 17.06 50

(a) Transmission Lines -Poles and associated lines 21,051.85 17.69 35

(a) Transmission Lines -Underground cables 2,559.73 22.99 50

(a) Transmission Lines -Submarine cables 9,468.37 12.25 45

(a) Transmission Lines -Easements owned by the Regulated Entity -

(a) Transmission Lines -Other 330.08 1.07 50

(a) Transmission Lines -Spares, spare parts and tools 684.25

(a) Transmission Lines -Land used for transmission lines 14,915.17

Subtotal - Transmisssion Lines 96,595.79

(b) Substation Components -Buildings, civil works and establishment 5,284.95 18.53 50

(b) Substation Components -Power Transformers 17,401.87 11.24 41.48

(b) Substation Components -Circuit breakers and Accessories 7,205.85 12.15 40

(b) Substation Components -Instrument transformers 3,766.20 12.67 40

(b) Substation Components -Protection and control equipment 2,001.41 12.43 15

(b) Substation Components -Power compensation equipment eg reactors 2,287.83 10.13 35.8

(b) Substation Components -Buswork, power and control cables 7,054.00 16.52 40

(b) Substation Components -Other 5,894.49 15.58 50

(b) Substation Components -Spares, spare parts and tools 1,036.98

(b) Substation Components -Land owned but used for substations 5,591.29

Subtotal - Substations 57,524.88

(c) Communication Plant -Buildings, civil works and establishment 157.24 8.23 15

(c) Communication Plant -Communications plant and infrastructure 2,295.17 9.53 15

(c) Communication Plant -Fibre optic cables 0.31 1.09 15

(c) Communication Plant -Fibre optic cable terminal equipment 1.94 0.45 15

(c) Communication Plant -Ancillary infrastructure 381.02 9.21 15

(c) Communication Plant -Other 2.24 0.46 15

(c) Communication Plant -Spares, spare parts and tools -

(c) Communication Plant -Land owned and used for communications plant -

Subtotal - Communications Plant 2,837.92

(d) Systems Operations -Buildings, civil works and establishment 2.37 8.46 15

(d) Systems Operations -Control room and control infrastructure 1,114.22 10.04 15

(d) Systems Operations -Ancillary infrastructure 398.65 11.02 15

(d) Systems Operations -Other 17.70 1.14 15

(d) Systems Operations -Spares, spare parts and tools 4.82

(d) Systems Operations -Land owned but used for system operations -

Subtotal - System O perations 1,537.75

(e) Metering Equipment Assets -Market meters 3.93 0.45 30(e) Metering Equipment Assets -Meters which are not Market Meters, Connection Assets or Sub-transmission assets 0.38 0.45 30

Subtotal - Market Meters 4.31

(f) Non-Network Assets -Computers, and office equipment 242.21 9.11 16

(f) Non-Network Assets -Plant, tools, and equipment 1,215.07 5.16 18

(f) Non-Network Assets -Furniture, fixtures, and fit t ings 81.01 5.34 18

(f) Non-Network Assets -Commercial buildings 156.86 28.75 50(f) Non-Network Assets -Land owned but used for non-network assets covers all land value not previously attributed 3.14

(f) Non-Network Assets -Other 852.28 7.27 15

Subtotal - Non-Network Assets 2,550.58

-

CWIP 6,894.74

-

TO TAL 167,945.97

Ngcp Draft Determination

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Transcript of Ngcp Draft Determination