Position Paper for NGCP under RTWR

Regulatory Reset

for the National Grid Corporation

of the Philippines (NGCP)

for 2011 to 2015

POSITION PAPER

September 9, 2009

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

POSITION PAPER

(FINAL)

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 the Implementing Rules and Regulations issued pursuant to that Act, the Energy Regulatory Commission (ERC) promulgated the Guidelines on the Methodology for Setting Transmission Wheeling Rates for 2003 to Around 2027 (ERC Case No. 2003–34, dated May 29, 2003, hereafter the ‘TWRG’).

The TWRG has subsequently been revised and re-issued as the Rules for Setting Transmission Wheeling Rates for 2003 to Around 2027 (ERC Case No. 2009-008RM, dated July 20, 2009, hereafter referred to as the ‘RTWR’).

Under Section 7.1.2 of the RTWR, the ERC must 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 was published on February 16, 2009 to fulfill this requirement, and Expository Hearings were held on February 17, 2009 for Luzon and February 19, 2009 for Visayas and Mindanao. Public Consultation was held on March 17, 2009. The ERC has been in receipt of written submissions on this Issues Paper. This Position Paper provides the ERC’s views on some of the primary inputs and approaches to be used for the regulatory reset process for NGCP in relation to the Third Regulatory Period.

This Draft Position Paper is circulated for a final round of written submissions, given the additional submissions from interested parties and the changes which have resulted from these submissions.

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REGULATORY RESET for the

NATIONAL GRID CORPORATION of the

PHILIPPINES (NGCP) for

2011 to 2015

POSITION PAPER

TABLE OF CONTENTS

CHAPTER 1 ...................................................................................................................... 1

INTRODUCTION AND TIME TABLE ......................................................................... 1 1.1 INTRODUCTION .............................................................................................................. 1 1.2 ERC’S ROLE & FUNCTION ............................................................................................ 2 1.3 RTWR & LEGAL POSITION ........................................................................................... 2 1.4 RTWR, OATS RULES AND ASPP CONSULTATION ................................................... 4 1.5 RELATIONSHIP TO THE NGCP’S MOTIONS FOR CLARIFICATION ...................... 4 1.6 TIMEFRAMES & PROCESS ............................................................................................ 5 1.7 APPOINTMENT OF INDEPENDENT EXPERTS ........................................................... 5

CHAPTER 2 ...................................................................................................................... 8

REGULATORY ASSET BASE ....................................................................................... 8 2.1 AVAILABLE APPROACHES TO ASSET BASE VALUATION ................................... 8 2.2 ADVANTAGES & DISADVANTAGES OF APPROACH .............................................. 8 2.3 PREFERRED APPROACH ............................................................................................... 9 2.4 DATA REQUIREMENTS ............................................................................................... 10 2.5 ASSET CATEGORIES “J” .............................................................................................. 11 2.6 OPTIMIZATION DURING REVALUATION ............................................................... 13 2.7 HISTORICAL AND RE-VALUED ASSET BASE ......................................................... 16 2.8 ROLLED FORWARD ASSET BASE ............................................................................. 17 2.9 WORKING CAPITAL REQUIREMENT ....................................................................... 18 2.10 CONSTRUCTION WORK IN PROGRESS .................................................................... 19 2.11 USE OF INDEPENDENT EXPERT ................................................................................ 20

CHAPTER 3 .................................................................................................................... 22

CAPITAL EXPENDITURE FORECASTS ................................................................. 22 3.1 GENERAL BASIS OF CAPITAL EXPENDITURE FORECASTS ............................... 22

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3.2 CAPITAL EXPENDITURE FORECAST PROCESS & JUSTIFICATION ................... 22 3.3 ACTUAL CAPITAL EXPENDITURE FOR 2005 TO 2009 ........................................... 28 3.4 CAPITAL EXPENDITURE FORECAST CATEGORISATION .................................... 29 3.5 ISOLATION OF CPI AND FOREIGN EXCHANGE IMPACTS ................................... 30 3.6 ASSET LIVES FOR FORECAST CAPITAL EXPENDITURE ..................................... 30 3.7 LOAD FORECASTS ....................................................................................................... 32 3.8 DATA REQUIREMENTS ............................................................................................... 33 3.9 RECONCILIATION TO FINANCIAL STATEMENTS ................................................. 33

CHAPTER 4 .................................................................................................................... 34

OPERATING & MAINTENANCE EXPENDITURE FORECASTS ....................... 34 4.1 GENERAL BASIS OF OPERATING & MAINTENANCE EXPENDITURE

FORECASTS ................................................................................................................... 34 4.2 OPERATING & MAINTENANCE EXPENDITURE FORECAST CATEGORISATION

.......................................................................................................................................... 34 4.3 ISOLATION OF CPI AND FOREIGN EXCHANGE IMPACTS ................................... 35 4.4 ACTUAL OPERATING EXPENDITURE FOR 2005 TO 2009 ..................................... 35 4.5 INCLUSION OF BENEFITS INTO OPERATING AND MAINTENANCE COSTS .... 36 4.6 RECONCILIATION TO FINANCIAL STATEMENTS ................................................. 36

CHAPTER 5 .................................................................................................................... 38

INCOME TAX AND OTHER TAXES, LEVIES AND DUTIES ............................... 38 5.1 GENERAL COMMENTS ON TAX ISSUES .................................................................. 38 5.2 ISOLATION OF TAX IMPACTS (OTHER THAN CORPORATE INCOME TAX) .... 40 5.3 UNDER AND OVER RECOVERY OF FRANCHISE TAX .......................................... 40 5.4 HISTORICAL PAYMENTS OF CORPORATE INCOME TAX ................................... 41 5.5 DATA REQUIREMENTS ............................................................................................... 42

CHAPTER 6 .................................................................................................................... 43

WEIGHTED AVERAGE COST OF CAPITAL ......................................................... 43 6.1 OVERVIEW ..................................................................................................................... 43 6.2 LOCKED PARAMETERS .............................................................................................. 45 6.2 ESTIMATE OF RISK FREE RATE IN THE PHILIPPINES .......................................... 45 6.3 DIRECT MEASURE OF RISK FREE RATE IN THE PHILIPPINES ........................... 45 6.4 IN-DIRECT MEASURE OF RISK FREE RATE IN THE PHILIPPINES ..................... 46 6.5 RISK FREE RATE IN THE USA .................................................................................... 47 6.6 CPI IN THE USA ............................................................................................................. 47 6.7 CPI IN THE PHILIPPINES ............................................................................................. 48 6.8 PHILIPPINES COUNTRY RISK PREMIUM ................................................................. 49 6.9 PHILIPPINES COUNTRY RISK PREMIUM ................................................................. 50

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6.10 REVIEW DIRECT AND IN-DIRECT MEASURE OF PHILIPPINES RISK FREE RATE ............................................................................................................................... 50

6.11 MEASUREMENT OF BENCHMARK EQUITY BETAS .............................................. 51 6.12 DE-LEVERING TO ASSET BETA................................................................................. 52 6.13 SELECTING A NGCP ASSET BETA ............................................................................ 52 6.14 RE-LEVERING TO NGCP EQUITY BETA................................................................... 52 6.15 ESTIMATED RANGE OF RETURN TO EQUITY ........................................................ 57 6.16 ESTIMATED RANGE OF DEBT MARGIN .................................................................. 57 6.17 ESTIMATED RANGE OF RETURN TO DEBT ............................................................ 57 6.18 ESTIMATED RANGE OF WACC .................................................................................. 57 6.19 COMMENTS ON DATA SOURCES AND WACC ESTIMATE ................................... 60 6.20 RECALCULATION POINT USING MARKET DATA ................................................. 60

CHAPTER 7 .................................................................................................................... 61

PERFORMANCE BASED REGULATION ................................................................ 61 7.1 PERFORMANCE INDICES FOR THIRD REGULATORY PERIOD ........................... 61 7.2 DETERMINATION OF PERFORMANCE TARGETS .................................................. 64 7.3 DETERMINATION OF REWARD / PENALTY TARGETS ......................................... 65

CHAPTER 8 .................................................................................................................... 69

ANNUAL VERIFICATION AND ADJUSTMENT OF TARIFF RATES ............... 69 8.1 BACKGROUND .............................................................................................................. 69 8.2 ISSUE 1 – CUSTOMER SEGMENTATION .................................................................. 69 8.3 ISSUE 2 – REVENUE RECOVERY BY SEGMENT ..................................................... 71 8.4 ISSUE 3 – CONNECTION SERVICES .......................................................................... 72 8.5 ISSUE 4 – SIDE CONSTRAINTS ................................................................................... 72 8.6 ISSUE 6 – MAR ALLOCATION BETWEEN GENERATORS AND LOADS ............. 73 8.7 OTHER ISSUES FOR CONSIDERATION .................................................................... 74

APPENDIX A .................................................................................................................. 76

ASSET BASE DATA TEMPLATES ............................................................................ 76

APPENDIX B .................................................................................................................. 77

CAPITAL EXPENDITURE FORECAST TEMPLATES .......................................... 77

APPENDIX C .................................................................................................................. 84

OPERATING & MAINTENANCE EXPENDITURE FORECAST TEMPLATES 84

APPENDIX D .................................................................................................................. 88

OPEX-RELATED TAX COST FORECAST TEMPLATES ..................................... 88

APPENDIX E .................................................................................................................. 91

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CORPORATE INCOME TAX TEMPLATES ............................................................ 91

Regulatory Reset Position Paper

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1

CHAPTER 1

INTRODUCTION AND TIME TABLE

1.1 Introduction 1.1.1 In May 2003, the Energy Regulatory Commission (ERC) adopted a

Transmission Wheeling Rate Guideline (TWRG) which had been developed through a public consultation process during 2002 and early 2003 (see ERC Case No. 2003 – 34). The final TWRG dated May 29, 2003 outlines a performance base regulation (PBR) framework which imposes a revenue cap on the National Transmission Corporation (TransCo) and/or its Concessionaire. The Concessionaire is now known to be the National Grid Corporation of the Philippines (NGCP). NGCP has taken over responsibility for operation and management of the Grid, while TransCo own or holds title over the regulated transmission assets. However for simplicity the Regulated Entity will be referred to as NGCP for the remainder of this document, although on occasion the requirements on the Regulated Entity shall in some circumstances be an obligation on TransCo.

1.1.2 This RTWR has subsequently been amended through a public consultation process during late 2008 and early 2009, and is now referred to as the Rules for Setting Transmission Wheeling Rates (RTWR). The RTWR is a PBR which the ERC has adopted as an alternative form of internationally-accepted rate-setting methodology under to 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 the Implementing Rules and Regulations (IRR).

1.1.3 Following public consultation, certain changes have been made by the ERC to the RTWR. These changes, which were not included in the Issues Paper, are reflected in this Position Paper.

1.1.4 This Position Paper is intended to be read in conjunction with the RTWR, which is a public document and available on the ERC website.1 Where deemed necessary, some clauses in the RTWR are therefore further explained and clarified in this Position Paper. Unless specifically noted in the Position Paper that it is intended to consider further change to the RTWR in the manner described, where any contradictions exist between the Position Paper and the RTWR, the RTWR should take precedence. To avoid the potential for confusion between instances where references are made to provisions in the RTWR or the Position Paper, all references to

1 http://www.erc.gov.ph/


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provisions from the RTWR will refer to Sections or Articles. References to provisions in the Position Paper will refer to Paragraphs.

1.2 ERC’s Role & Function 1.2.1 The RTWR specifies that the ERC publish an Issues Paper to commence

the regulatory reset process, not later than 21 months prior to the start of each Regulatory Period. The Issues Paper published on February 16, 2009 fulfils this requirement and presented additional information on the broad approach the ERC believed should be adopted to implement the PBR for the regulatory reset for the Third Regulatory Period. This information was to guide NGCP in preparing its filing for a new revenue cap under Article IV of the RTWR for the Third Regulatory Period commencing January 1, 2011. The Issues Paper also provided additional guidance to the Independent Expert(s) who shall be appointed to assist and advise the ERC during the regulatory reset process.

1.2.2 The ERC has undertaken Public Consultation and received written submissions on the issues raised in the Issues Paper and has developed final positions on some of these. This Position Paper presents the final views on some issues and indicates where there is further action or consultation required by NGCP and/or interveners and oppositers before the ERC can finalize its view.

1.2.3 By notice of this Position Paper the ERC requires that NGCP submit its filing for a regulatory reset review including all data, reports, forecasts and information required by the RTWR for this process, to the ERC no later than December 1, 2009.

1.3 RTWR & Legal Position 1.3.1 The following paragraphs outline in broad terms the elements of the

alternative rate-setting methodology for NGCP which the ERC has adopted, which can be broadly defined as a performance-based price-control regime, and is described in more detail in the RTWR. The RTWR is an alternative internationally-accepted rate-setting methodology as allowed under Section 43(f) of the EPIRA, and Rule 15, Section 5(a) of the IRR issued pursuant to that EPIRA by the ERC.

1.3.2 The alternative rate-setting methodology which has been adopted by the ERC is one which is based on a revenue cap which has been in place since 2003. The revenue cap for the third and subsequent regulatory periods shall be based on a regulatory reset (or review) which shall conclude prior to the commencement of the five (5) year regulatory period. This reset shall lock in place the prime regulatory parameters for the remainder of the Third Regulatory Period, which cannot be re-opened unless particular triggers are met. The revenue cap shall be based on recovery of the forecast efficient costs of the delivery of electricity transmission services over the regulatory period. Note the revenue cap does not cover the costs


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of electricity distribution (ie: cost of wheeling energy through the distribution networks) or the costs of electricity supply (ie: cost of retail delivery) or the costs of electricity generation (ie: cost of energy).

1.3.3 Efficient costs require consideration of efficient operating and maintenance costs, a return of efficiently deployed capital (ie: depreciation of efficiently deployed assets over their economic life, where regulated transmission network assets are grouped into like asset categories), and a return on efficiently deployed capital (ie: a regulatory cost of capital times the written down value of the regulated asset base). Here the regulatory asset base for the forecast period should be established from a rolled-forward asset base without inflation, plus prudent capital expenditure, less depreciation and less sold (for example sub-transmission) or retired or written-off assets. The starting point at the beginning of the forecast period can be a re-valued asset base, optimized for capacity over a reasonable planning horizon, and configured on existing easements and rights of way. The revenues thus derived shall be smoothed to avoid rate shock over the regulatory period. Note that sub-transmission assets sold by TransCo shall be valued at their revenue potential, and be considered as a disposal of regulated assets.

1.3.4 The forecast revenue requirement over the five (5) year regulatory period will then be converted to a smoothed revenue cap. This revenue cap will be recalculated annually and be allowed to adjust automatically as external economy wide factors change. The primary adjustment factor will be the Consumer Price Index (CPI). There will be an additional adjustment applied based on the US$ to Peso exchange rate when particular triggers are met. In the normal course of economic development, such triggers are unlikely to be met, and the exchange rate adjustment is not likely to apply. Note that the ICERA style automatic exchange rate adjustment mechanism does not apply for the transmission network assets under this new methodology. Exchange rate adjustments shall only be applicable when certain triggers have been met.

1.3.5 The rate translation process will be undertaken annually to ensure the sum of the regulated indicative prices derived from the total of the individual tariff revenues plus assigned revenues from related businesses, are less than the recalculated revenue cap. Tariff changes year-by-year will be subject to side constraints recognizing the need for slow changes in tariff levels for customers to remove any emerging cross subsidies due to capital expenditure programs. An over and under recovery process shall be adopted to ensure the revenue cap is not breached. Consideration to issues such as the definition of customer segments, the approach to tariff structure and other tariff issues shall be considered at each major reset process and in particular for the reset for the Third Regulatory Period covered by this Position Paper.


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1.4 RTWR, OATS Rules and ASPP Consultation 1.4.1 Through a Notice dated November 11, 2008 and November 18, 2009, the

ERC commenced a review of the RTWR, the OATS Rules and the ASPP, respectively, in order to determine what, if any, changes are required before these rules are implemented for the revenue reset for the Third Regulatory Period. Consideration of amendments to these three rules is being undertaken in parallel because they interact together and support the regulatory framework imposed on NGCP, and the ERC is seeking to ensure further harmonization between these three documents.

1.4.2 In order to avoid confusion between the previous TWRG and the amended rules once they are finalised, the ERC has moved to call the amended rules the Rules for Setting Transmission Wheeling Rates (RTWR).

1.4.3 The consideration of the changes to these three rules is being undertaken in parallel with the implementation of the RTWR rules through the Issues Paper process. To the greatest extent possible, these consultation and hearing processes shall be run in parallel to achieve the most feedback possible on the regulatory reset for NGCP, and to allow better harmonization between the three rules.

1.5 Relationship to the TransCo’s Motions for Clarification 1.5.1 In parallel with the rule changes described above, the ERC is also

addressing its response to the Motions for Clarification filed by TransCo as follows:

(a) Motion for Clarification, dated July 12, 2006;

(b) Supplemental Motion for Clarification, dated February 21, 2007; and

(c) A letter from TransCo in relation to the Motion for Clarification and the Supplemental Motion for Clarification, dated January 31, 2008.

1.5.2 To the extent the detailed response to these Motions for Clarification (MC) requires changes to clarify the rules, such changes will be included in the rule amendment processes discussed in paragraphs 1.4 above. To the extent the MC impact on the analysis of detailed capital expenditure projects during the Second Regulatory Period, the optimization of assets during the regulatory reset for the Second Regulatory Period, and the NGCP filing for the Third Regulatory Period, the ERC intends to complete the Order on the MC around the same timeframe envisaged for the publication of its Position Paper, and shall include some of the clarifications as approaches to be used in for the Third Regulatory Period.


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1.6 Timeframes & Process 1.6.1 Having made the amendments as listed above the timetable for the public

consultation shall, to the greatest extent possible adhere to the following timetable.

• Issues Paper was published on February 16, 2009;

• Public Exposition was undertaken on February 17, 2009 for Luzon, February 19, 2009 for Visayas and Mindanao (to describe the approaches proposed in the Issues Paper);

• Written submissions on Issues Paper closed March 16, 2009;

• Public Consultation occurred on March 17, 2009 (to seek public feedback on the Issues Paper);

• Given additional changes a draft Position Paper will be published on or before August 5, 2009, allowing a further period to August 21, 2009 for further written submissions and finalization of the Position Paper on or before September 7, 2009;

• Reset Application filed by NGCP by December 1, 2009;

• Order for Publication of Notice of Public Hearing mid December 2009;

• Public Hearings on December 2009 to March 2010;

• NGCP reset Draft Determination published before April 30, 2010;

• Public Exposition by May 2010;

• Public Consultation by June 2010 (to seek public feedback on the Draft Determination);

• NGCP reset Final Determination published end of July 2010;

• NGCP file Translation of Revenue Cap into Rates by end August 2010;

• Public Hearings on Rate Translation during September-November 2010;

• Order on Rate Translation by end November 2010; and

• NGCP implement new rates from January 1, 2011.

1.7 Appointment of Independent Experts 1.7.1 The RTWR confers on the ERC the right or obligation to retain a

Independent Expert or Experts in relation to a number of matters, during each regulatory reset process, including:

(a) determining the Regulatory WACC (Clause 4.9.2 & 5.9.3 of the RTWR);


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(b) undertaking a review of asset re-valuation and the preparation of a report in this regard (Clause 4.6.2 of the RTWR);

(c) preparing a report on the condition of assets used to provide Regulated Transmission Services and the regulatory life that should be attributed to these assets (Clause 4.8.3 of the RTWR);

(d) reviewing the capital expenditure forecasts of Regulated Entities (Clause 4.10.1 of the RTWR);

(e) reviewing the operating and maintenance expenditure of Regulated Entities (Clause 4.11.4 of the RTWR);

(f) reviewing, remodeling or recalculating of the forecast financial accounts and ratios (Clause 4.20.3 & 5.19.2 of the RTWR); and

(g) any other matter in respect of which the ERC determines it requires assistance for the Regulatory Reset Process.

1.7.2 The fees for the Independent Expert or Experts must be borne by the Regulated Entity. The terms under which the fees shall be paid are to be included in a contract to be drafted by the ERC between the Reset Expert or Experts and the Regulated Entity. The conditions for engagement of a Independent Expert or Experts are described in Article XIV of the RTWR. This includes a description of the expertise required and the manner in which the fees for the Independent Expert or Experts will be recovered from Regulated Entities.

1.7.3 Appendix B to the RTWR sets out the criteria for the required experience and qualifications of Independent Experts.

1.7.4 The ERC gives notice that in terms of paragraph (g) above, it has appointed, or may appoint a Independent Expert(s) to assist it with the following aspects related to the Regulatory Reset Process:

(a) project managing the overall regulatory reset processes for the ERC and coordinating the Independent Expert or Experts, including the preparation of regulatory documentation and financial models;

(b) valuation of the regulatory asset base of the Regulated Entities;

(c) review of the prior capital and operating & maintenance expenditure of the Regulated Entity during the Second Regulatory Period against the forecast expenditures approved at the last regulatory reset to assist with implementation of Article IX of the RTWR;

(d) review of the proposed capital and operating & maintenance expenditure of the Regulated Entity during the Third Regulatory Period; and


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(e) setting the regulatory Weighted Average Cost of Capital (WACC).


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2

CHAPTER 2

REGULATORY ASSET BASE

2.1 Available Approaches to Asset Base Valuation 2.1.1 Section 4.6 of the RTWR outlines the primary requirements of the asset

valuation which is required to be undertaken to assist with the regulatory reset process for NGCP. Section 5.6.1 of the RTWR requires that an asset valuation be done for the Third Regulatory Period. However Section 4.6.4 of the RTWR allows three different approaches to asset valuation (or a mix of the three). These are:

(a) Indexation from the prior regulatory asset valuation;

(b) Absolute valuation by replacement cost analysis; and

(c) Absolute valuation using modern equivalent asset analysis.

2.1.2 In its Final Determination for the Second Regulatory Period, the ERC accepted the use of a mix of all three approaches by the Regulatory Expert assisting with the asset valuation.

2.2 Advantages & Disadvantages of Approach 2.2.1 The advantages of an indexation approach are that it is easier to undertake

and can be performed as a desk-top study based on the prior asset valuation and asset register developed for regulatory purposes. This takes less resources and time that the other two methods. The disadvantages of the indexation approach are that the prices for electricity transmission assets usually do not move in relation to a broad independent measure of price change such as the Consumer Price Index (CPI). Producer input price indices may be better measures of the changes in asset value, but availability of the index will drive the ease of asset valuation using this approach.

2.2.2 The advantages of absolute valuation by replacement cost analysis include that the existence of the physical assets are usually identified against the network line diagrams and asset registers, which allows identification of missing and redundant assets in the asset register. It allows an update of the asset register for accounting purposes as well as for regulatory purposes. Also replacement cost analysis allows the latest prices for various components of the network to be updated for the most recent purchase and for changes in exchange rate and metal prices. The disadvantages include that it does not necessarily recognise advancements in modern equipment availability and can give a replacement cost for a particular level of functionality, which is now available in more modern form at less cost. Also the approach requires considerable resources to


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perform reasonably and can take form three to six months to perform depending on the size of the transmission network.

2.2.3 The advantages of absolute valuation using modern equivalent asset (MEA) analysis include all those mentioned in 2.2.2 for the replacement cost analysis, but the approach also eliminates the disadvantage with that methodology where modern assets would be chosen to replace existing asset functionality today if replacement was required, and at lower cost. This approach leads to a more economically efficient asset value estimate than either of the first two approaches. The other disadvantages identified in 2.2.2 also exist, with the overlay that MEA analysis requires excellent data on the name plate capacity and functionality of all major asset groups, and this is rarely available in existing asset registers. Additional time, cost and expertise is required to use this approach.

2.3 Preferred Approach 2.3.1 The ERC received a number of submissions on its suggestion in the Issues

Paper to move to using an indexation based approach to the asset base valuation for the RAB at the commencement of the Third Regulatory Period. The ERC has decided to follow two approaches to asset valuation for the Third Regulatory Period.

2.3.2 The primary approach will be to undertake the asset valuation using optimised depreciated replacement cost (ODRC) techniques as described in Article IV of the RTWR, with the assistance of the Independent Expert in valuation, for reasons including:

(a) A concern that all of the transmission assets were not identified to the ERC during the regulatory reset for the Second Regulatory Period and that these were best valued using the same techniques as were previously employed (refer NGCP’s submission of April 2, 2009 which disclosed further found assets);

(b) The need to fully understand the impact of using an indexation approach and its advantages and disadvantages for both consumers and the regulated entity;

(c) The need to adequately define in writing and consult on an index methodology before it was fully implemented;

(d) A concern that compliance with the stated approaches allowed under Article V of the RTWR required the use of an ODRC methodology for the Third Regulatory Period before other approaches could be utilized for Subsequent Regulatory Periods.

2.3.3 The secondary approach will be to undertake a parallel asset valuation using an indexation approach, with the assistance of the Independent Expert in valuation, to allow assessment of:

(a) The granularity at which an indexation valuation should occur;


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(b) Which indices best allow a reasonable approach to valuation, given the costs of a transmission business do not usually follow the general consumer price index (CPI);

(c) The relationship between the asset registers held for accounting purposes and the physical assets identified as transmission assets; and

(d) The level of resources required to undertake an indexation valuation in relationship with the accuracy which is derived from this technique.

2.3.4 The revenue path for NGCP shall be derived using the asset valuation derived using the ODRC methodology, and with the assistance of the Independent Expert. The asset valuation derived using the indexation methodology shall be used to inform the ERC of the potential pluses and minuses of this methodology, and the issues which must be addressed should this methodology be used for the Subsequent Regulatory Periods.

2.4 Data Requirements 2.4.1 In all other respects the ERC proposes to use the same data categories that

were used in the regulatory reset for the Second Regulatory Period updated for the submissions received. The detail of the data requirements are repeated here for clarity.

2.4.2 In applying the OATS Rule, NGCP has separated its asset base into three primary asset types as follows, and these should be maintained:

(a) Connection Assets;

(b) Residual Sub-transmission assets (not yet sold); and

(c) The Regulatory Asset Base (RAB) subject to revenue cap under the RTWR.

2.4.3 In deciding what customer segmentation it preferred, TransCo previously identified the RAB assets against the three primary transmission networks, being Luzon, Mindanao and Visayas. At the request of the ERC at the regulatory reset for the Second Regulatory Period it also identified the island interconnection assets separately as a fourth group of assets. In order to further examine the issues raised by the revenue recovery allocation between customer segments, the ERC requires that the asset valuation information provided by NGCP under Section 4.6 of the RTWR continue to be broken down into the same groupings as follows:

(a) Luzon grid, excluding inter-island interconnection assets;

(b) Visayas grid, excluding all inter-island interconnection assets;

(c) Mindanao grid, excluding all inter-island interconnection assets; and


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(d) All inter-island interconnection assets, identified separately for each main inter-island interconnector.

2.4.4 The ERC requires that the inter-island interconnection assets thus isolated should include those transmission lines which are on land but support the submarine (or over-water) island interconnection, back to the primary sub-station which controls the flow of electricity to each side of that interconnection. The primary substation assets used for interconnection should be grouped with the interconnection assets.

2.4.5 The ERC notes the Annex E of the NGCP submission dated April 2, 2009 on customer segmentation and its examination of options relating to the recovery of the costs associated with the inter-island interconnection assets. While concluding that no change should occur to customer segmentation for the Third Regulatory Period (which will be discussed further below in paragraph 8.2), the reasons for the ERC requiring this separate identification of inter-island interconnection assets is clearly apparent. This separate identification should continue.

2.5 Asset Categories “j” 2.5.1 Section 4.6.5 of the RTWR specifies the Asset Categories “j” which

NGCP and the Independent Expert should use to re-value the transmission assets. The ERC requires the following additions to this list to ensure there is transparency of the assets consigned to NGCP under Republic Act No. 9511 and the Concession Agreement which underlie the services provide by NGCP:

(a) Add word “including CTS and CS, electrode lines and accessories” before “sub-sea cables” to sub-point (v) of point (a) for clarity;

(b) Add word “spare parts and tools” before “spares” to each relevant sub-point of points (a), (b), (c) and (d) for clarity;

(c) Include point (ix) “land owned but used for transmission lines” in point (a);

(d) Add word “transmission” before “substation” to point (b), “power” before “transformer” to sub point (ii), “and accessories” after “circuit breakers” to sub point (iii), “and control equipment” after “protection” to sub point (v), “power compensating equipment, eg:” before “reactors” to sub point (vi), and “power and control cables” after “busses” to sub point (vii), all of point (b) for clarity;

(e) Include point (x) “land owned but used for transmission substations” in point (b);

(f) Include point (iii) “fibre optic cables” and point (iv) “fibre optic cable terminal equipment” in point (c);

(g) Include point (viii) “land owned but used for communications plant” in point (c);


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(h) Include point (v) “spares, spare parts and tools” in point (d);

(i) Include point (vi) “land owned but used for system operations” in point (d);

(j) Include point (e) “metering equipment assets”, and the sub points (i) “market meters” and (ii) “meters which are not market meters, Connection assets or Subtransmission assets”;

(k) Add words in point (vii) “land owned and used for non-network assets covers all land value not previously attributed” after “Land” in point (f); and

(l) Include point (g) “Found Assets” with point (i) “Assets found between a Regulatory Period and the Subsequent Regulatory Period (*1)” and include table note “Note (*1). But not related to capital expenditure, and submitted to the ERC during a regulatory reset process for approval and inclusion in the RAB for the next regulatory reset” at the bottom of the table.

2.5.2 Note that the ERC has changed the term “used” as proposed by NGCP to “owned but used” as it is inappropriate to gain a recovery through inclusion in the RAB of assets which are either contributed, leased or accessed for free in the reasonable costs for recovery under the revenue cap. The important principle of no double recovery of efficient costs is important in relation to land and easements used to support infrastructure which is used to provide transmission services. Also note, that the ERC has adopted many of the additional clarification words proposed by NGCP in its April 2, 2009 submission. It should be noted that for the purposes of this discussion on transmission assets these have been consigned to NGCP under Republic Act No. 9511 and the Concession Agreement, and TransCo retains ownership and holds title over these regulated transmission assets.

2.5.3 Appendix A provides the asset category reporting template to be delivered to the ERC. This template should be used to provide the data on both re-valued cost and the historical cost of the various asset categories. It should also be used to provide the written down value of both the re-valued cost and the historical cost of the various asset categories to their current age as at December 31, 2010, or weighted average age, as the case may be.

2.5.4 The ERC notes that the valuation undertaken on an ODRC basis will likely use different functional groupings of assets than is provided in the RTWR with changes as summarised in paragraph 2.5.1 and Appendix A of this paper. This occurs because the replacement cost valuation of some assets using an ODRC methodology is done on a functional group basis, eg: a ‘switch bay’ basis rather than on an individual sub-asset basis which an indexation methodology might use, eg: busbar, cable, circuit breaker, control equipment etc. For example, in the ODRC approach, the current


Page 13

efficient cost of a ‘switch bay’ of a particular type, voltage and configuration is estimated by component to create a cost of the functional group, then multiplied by the number of ‘switch bays’ of that type to arrive at the value of this type of asset. In the indexation approach the change in value of the sub-asset grouping is estimated, independent of an understanding of the current efficient deployment of the functional group. This fundamental difference is what the ERC shall look at during this regulatory reset, for potential use of an indexation methodology in Subsequent Regulatory Periods.

2.5.5 It should also be noted, that in updating the accounting records which are likely held on a sub-asset basis, for a valuation undertaken on an ODRC basis using functional asset grouping, the usual approach to readjusting the accounting record is to apply allocations of the weighted functional valuation change to the sub-asset category values based on a mapping of the sub-assets to the functional groups. While this is an issue for the financial reporting of the regulated entity, such mapping is not strictly necessary for rate setting purposes under the PBR building block approach. Where necessary the opening asset base can be rolled forward on the ODRC asset breakdown basis, the analysis of forecast taxes can be modelled on the historical cost asset breakdown basis, and where necessary, capital expenditure projects can be modelled on either approach, depending on how the information is delivered to the ERC. While the ERC would prefer to have opening asset base, capital expenditure and historical asset base all using the same asset categories, this may not be practical or possible for the application by NGCP.

2.6 Optimization During Revaluation 2.6.1 The ERC has indicated in Section 4.6.6 of the RTWR that it prefers the use

of an optimisation methodology to be overlayed on the asset valuation for the NGCP assets. Section 5.1 of the RTWR indicates that optimization should continue if it makes sense in the context of the asset valuation. The ERC remains of the view that optimization is necessary to assist the principle of only recovering economically efficient costs in the building block analysis. The ERC is aware of the submissions from NGCP which suggest optimization is not strictly necessary where the growth in connections, load and energy take-off from the transmission network continue to grow at a reasonable rate. Fairly high levels of growth do exist in the Philippines, and the argument is that any over capacity or design in excess of the requirements in the next Regulatory Period of five years is likely to be utilized in the following period, thus making optimization unnecessary within the Philippines. The ERC believe this issue should be further examined before the Fourth Regulatory Period in conjunction with the proposal to move towards an indexation valuation methodology, because optimization of unneeded assets is more difficult where an indexation methodology is used for valuation.


Page 14

2.6.2 The following additional guidance is provided to the NGCP and the Independent Expert on how this optimisation should be undertaken for the NGCP asset base to be used as the opening RAB for the Third Regulatory Period.

2.6.3 There are two aspects to the optimisation process:

(a) Optimisation of the network configuration (eg: network security, level of redundancy, statutory requirements for certain assets, network safety);

(b) Optimisation of the network alignment (ie: a brownfield approach is specified by Section 4.6.6 (c) of the RTWR, where existing connection points and alignments are assumed to remain in place); and

(c) Optimisation of the installed assets (eg: review of over design, over capacity, inappropriate design).

2.6.4 The Figure 2.1 outlines the high level decision process required by the ERC on the inclusion or exclusion of existing assets into the RAB for pricing purposes.

StartIs the line

or substationrequired now?

Exclude assetsfrom optimized

networkNo

Yes

Doesrating exceed

15 yearrequirement?

Include assetsin optimized

networkat reduced rating

Yes

Include all in optimized network

No

Figure 2.1 : Base Optimization Flow Chart

2.6.5 The basic steps in the optimization process are as follows:

(a) Review NGCP’s network planning criteria to determine whether they are in accordance with “good electricity industry practice”.


Page 15

Any optimization carried out on the network configuration or assets must meet current good practice planning criteria. Optimization which has the potential to breach current good practice planning criteria should not be pursued.

(b) Review the design criteria for the primary existing network assets to determine if they are in accordance with good practice for the location and application of those assets. If the design criteria result in the assets being over-designed compared to good practice they should be optimized down in value to good practice.

(c) Review operating criteria, practices and performance as required to ensure that operating constraints are considered as part of the optimization process.

(d) Review the forecast load, generation and interconnector power flows for the nominated planning horizon (here 15 years under Section 4.6.6 (b) of the RTWR). The selection of the period must also take into consideration that most transmission assets can only be installed in relatively large blocks.

(e) Review asset ratings and optimize if necessary.

(f) Carry out network studies of optimized network to ensure the optimized network and its configuration meets the required levels of service and quality and good practice.

2.6.6 For those assets optimized in the regulatory reset for the Second Regulatory Period, the ERC requires the Independent Expert to review these assets to see whether they now meet the criteria to allow them to be included into the asset base. The process in Figure 2.1 should be followed. Where assets values are to include the value previously optimized out of the RAB, should the depreciated value of the assets as at the date of its exclusion from the RAB, as required by Section 5.6.2 of the RTWR.

2.6.7 The ERC does not believe the optimization process should occur in the manner of a “greenfield” study, but rather it should use “brownfield” techniques. Thus where the transmission network has evolved with result that there are now two transmission lines running in parallel, one of an earlier vintage and (possibly) lower voltage level, and the later line with higher voltage and more modern equipment, the two lines would not be optimized to one, but rather the two lines would be re-valued at the voltage levels they currently serve. No optimization should occur in such circumstanced, provided only that the initial investment met reasonable planning guidelines at that time.

2.6.8 The feedback during public consultation sessions and in written submissions provided to the ERC suggests a fifteen (15) years planning horizon is reasonable for transmission assets (any shorter period being likely to forestall potential larger projects which otherwise should have


Page 16

progressed), and did not otherwise comment on the proposed high-level optimization process provided above. The ERC understands that the Department of Energy (DoE) continues to prepare the Transmission Development Plan (TDP) using a ten (10) year forecast period, and that this is assisted by information provided in previous years by TransCo and from now forward by NGCP. The ERC shall use a reasonable planning horizon of fifteen (15) years to match the analysis undertaken by NGCP and will observe the differences between the NGCP forecasts and the TDP forecasts over the overlap period for the assessment of optimized assets for inclusion in the RAB. The ERC notes that in other respects there are differences in the objectives of the TDP and the capital expenditure forecasts required for rate setting purposes, and as such while there should a relationship to the TDP, the forecasts required by the ERC may differ in other respects. Typically the Independent Expert and the ERC shall concentrate on the non-coincident peak demand levels on a line and substation basis, whereas the TDP concentrates more heavily on the coincident peak demand for each Grid in order to identify existing and new loads and the potential opportunities for new generator investment.

2.6.9 The ERC did not receive any submissions with specific guidance on which engineering standards, planning guidelines or other benchmarks which could be used to define “good electricity industry practice” in the Philippines, and in particular how this might impact on the asset valuation or the optimization of the network assets as required by the RTWR. However, the ERC has confidence that with the combined experience of NGCP and the Independent Expert for the asset valuation, appropriate recommendations from the Independent Expert will be provided in its asset valuation report, which is independent of NGCP and/or TransCo. In addition, should NGCP have concerns on any matter included in the asset valuation report, it can raise these concerns in its application, and provide justifications to the ERC as to why it believes its approach to these technical engineering and planning issues should outrank those provided by the independent expert.

2.6.10 Following a rigorous tender process, on July 6, 2009, the ERC appointed Sinclair Knight Merz Pty Ltd (SKM) as the Independent Expert for the asset valuation for the Third Regulatory Period. In the processes required to support SKM in developing the asset valuation of the transmission network, NGCP will likely have queries or comments on particular issues which might be raised by the optimization process or the valuation methodologies employed by SKM. NGCP will be able to voice these queries along the way, but also formally in its application, and later in submissions and public hearings on the ERC’s Draft Determination report.

2.7 Historical and Re-valued Asset Base

2.7.1 To the extent NGCP is subject to corporate income tax, in undertaking a forward estimate of the corporate income tax payable each year during the


Page 17

second regulatory period (see Section 4.12 of the RTWR), the information on depreciated historical cost of the assets will be required as at December 31, 2010. This value will be used in a calculation of a rolled forward historical cost asset base in order to determine an estimate of the depreciation of each asset category on an historical cost basis, in order to work out an estimate of the forecast taxable income for NGCP for each forecast year.

2.7.2 The submission from NGCP dated April 2, 2009 indicates that is can again provide the historical and the re-valued asset base in a similar manner as it did for the Second Regulatory Period. This will allow the ERC to model the historical roll-forward asset base for the forecast years of the Third Regulatory Period, recognizing that the effect of the Franchise Act of NGCP, Republic Act No. 9511, will have an impact on whether the calculation of corporate income tax will apply for the Third Regulatory Period. In effect the ERC believes forecast income tax shall fall to zero during the forecast period.

2.7.3 However, the submission provided by NGCP dated April 17, 2009, which was focused on the methodology to implement the analysis according to the provisions of RA 9511, suggests that the historical cost depreciation will still be required to assess NGCP’s forecast franchise tax obligation for the forecast period. Given the comments in paragraph 2.7.2 above, and the comments on paragraph 5.1.8 below, the ERC does not believe the historical roll-forward asset base for the forecast years of the Third Regulatory Period is required. Should NGCP believe this is required, it should provide this information in its submission and justify the reason for the use of this information in application for the revenue ca for the Third Regulatory Period. The ERC provides further comments on the franchise tax analysis at paragraph 5.3 below.

2.8 Rolled Forward Asset Base 2.8.1 The Valuation Report to be provided by the Independent Expert will

provide the optimised indexed cost of the NGCP asset which are commissioned and in service at December 31, 2008. While the ERC would prefer to have the value as at December 31, 2009 this may not be possible given the ERC prefers to have the asset valuation report delivered by the Independent Expert by around October 2009. The ERC shall assume the valuation is at December 31, 2008, unless advice from the Independent Expert suggests this can be provided as at December 31, 2009. In order to move this value forward to December 31, 2010 (the day prior to the start of the Third Regulatory Period), the techniques in Section 4.6.10 of the RTWR shall be used.

2.8.2 In particular this requires the ERC to adopt the “actual or budgeted capital expenditure of the Regulated Entity” for the 12 month period of 2010. It further requires the ERC to assess whether these expenditures are


Page 18

“reasonable” and “if they had been in existence as at the date of the Initial Re-valuation” would have been included in the regulatory asset base. The ERC shall request the Independent Expert appointed to review and advise on the actual and forecast capital expenditure to review the 2009 (possibly) and 2010 capital expenditure program of NGCP (including those prior years for larger projects which are underway but not yet commissioned) using the optimisation principles previously discussed and to be used for developing the initial asset base revaluation as at December 31, 2010.

2.8.3 In analysing the capital expenditure which has occurred and has been commissioned during the Second Regulatory Period, the ERC is concerned that there should be no double count of these assets and the assets which are to be re-valued in the RAB during the re-valuation process. The ERC shall request the Independent Expert appointed to review and advise on the actual capital expenditure commissioned during the Second Regulatory Period to liaise with the Independent Expert appointed to undertake the valuation at the beginning of the Third Regulatory Period with the objective to ensure there is no double count of this capital expenditure in the opening asset base.

2.8.4 Section 4.6.10 also requires the ERC to review those assets existing at the re-valuation date, currently assumed to be December 31, 2008, unless otherwise approved by the ERC, which are subsequently sold in the 2009 or 2010 year (predominantly associated with sale of sub-transmission assets to Distribution Utilities). Where and if those assets which are disposed of are sold for a value less than the optimized depreciated roll-forward cost, the net value (being the difference between the sale value and the optimized depreciated roll-forward cost) shall be retained within the RAB as a separate regulatory asset to be depreciated over its remaining life as if it had remained in the NGCP’s ownership. Such treatment provides regulatory certainty for NGCP but ensures that transfer to sub-transmission assets to Distribution Utilities at their revenue potential.

2.8.5 Section 4.7.2 of the RTWR indicates how the regulatory asset base shall be rolled-forward as a forecast from January 1, 2011 to December 31, 2015. Because the ERC did not receive any substantive comments on these roll-forward issues the application of the methodology defined by these clauses of the RTWR should be followed.

2.9 Working Capital Requirement 2.9.1 Section 4.5.7 of the RTWR sets out the building block analysis which shall

be used to determined the annual revenue requirement for NGCP each year for the of the Second Regulatory Period. This analysis includes an amount called working capital, which will be included in NGCP’s revenue requirement to compensate it for the delay between those cash flows entering its business from customers and those leaving its business to suppliers. Such level of working capital should be set at a level which is


Page 19

reasonable for an efficient organisation working as an electricity transmission company. The ERC intends to continue to allow a working capital allowance for the Third Regulatory Period as allowed under Section 5.5.1 of the RTWR.

2.9.2 The RTWR specifies that the working capital should be set at a proportion of the forecast operating & maintenance expenditure less bad debts, the ERC has yet to specify an acceptable proportion which could be used for the forecast period. Methodologies which could be used to set this proportion include:

(a) Benchmarking against other electricity transmission companies in other jurisdictions;

(b) Benchmarking against other Philippine companies in the utility sector, either in the electricity or telecommunications or water sectors;

(c) Undertaking a specific lead-lag study of NGCP over a 12 month period (note this could be expensive and time consuming depending the level of detail at which the study is performed);

(d) Set at a theoretical level for an efficient company, say 30 days of sales revenue;

(e) Other methodologies which may be relevant.

2.9.3 The ERC received comments from NGCP on how it should set the allowed proportion of working capital to be included in the annual revenue requirement, and which is compatible with the building block methodology being employed for the forecast period. In effect given the initial short period in which NGCP has been operating (less than three months) the methods suggested above may not provide reasonable answers. NGCP has suggested using the same percentage as was used for the Second Regulatory Period. The ERC believes this is reasonable but shall consult further following the publication of its Draft Determination in order to gather more up-to-date views on the working capital requirement.

2.10 Construction Work In Progress 2.10.1 The construction work in progress (CWIP) adjustment process occurs in

two places within the analysis of NGCP’s annual revenue requirement for the Second Regulatory Period. CWIP is added to both:

(a) The opening RAB to accommodate the cost of investment lag between the commencement of the design phase for a particular electricity transmission project (or group of assets) and the commissioning of those assets, but on the assumption there is no double count from the indexation approach used); and

(b) The actual or budgeted capital expenditure, during the 2009 and 2010 years (where the asset valuation is as at December 31, 2008),


Page 20

or, only the 2010 year (where the asset valuation is as at December 31, 2009). Such actual or budgeted capital expenditure as approved by the ERC for inclusion in the roll-forward to the opening RAB at December 31, 2010.

2.10.2 Section 4.6.9 of the RTWR suggests ways in which the CWIP might be estimated. These include:

(c) Uniformly escalating the optimized depreciated replacement cost of the re-valued assets by a constant factor; or

(d) Directly estimating the investment cost for specific past projects and adding this cost to the optimized depreciated replacement cost of the re-valued assets; or

(e) Other methodologies.

2.10.3 The ERC recognizes that the simplicity of a single escalation factor to all asset categories may be offset by perceived inaccuracy of an allowance of recovery of this reasonable investment cost. Issues which need to be considered include whether:

(a) one factor for all assets categories is sufficient;

(b) one factor for transmission line and one for substations would be sufficient;

(c) over what time frames do the average transmission line and average substation investment occur, prior to commissioning;

(d) the discount rate used to estimate the CWIP factor should be the regulatory WACC or just the estimated cost of debt;

(e) there is an average capital expenditure profile which should be used to estimate the cost of investment prior to commissioning.

2.10.4 The ERC notes that the building block methodology provides compensation for the time-value-of-money in the forecast period, so an additional CWIP for capital expenditures during this period is not required.

2.10.5 NGCP has indicated it will seek external advice on the value or escalation factor for the CWIP to be used in both the initial revaluation and the single year roll-forward to the opening RAB, and include this in its application. Thus the ERC suggests further consultation on this issue shall arise from the application and from the Draft Determination report.

2.11 Use of Independent Expert 2.11.1 Section 4.6.2 of the RTWR provides for two approaches for NGCP to re-

value its asset base for regulatory purposes. At this point the ERC has implemented its preference to follow the approach outlined in Section 4.6.2 (b) of the RTWR and the ERC has requested NGCP retain the services of an Accredited Independent Expert which could both undertake


Page 21

the revaluation and advise the ERC on any points of methodology or approach which would allow the principles the ERC has adopted in the RTWR to be employed in a reasonable manner. The ERC requires the Independent Expert to report directly to the ERC rather than to NGCP as occurred for the regulatory reset for the Second Regulatory Period. Better access to the Independent Expert by the ERC is required for the regulatory reset for the Third Regulatory Period.

2.11.2 The ERC notes that in order to get the requisite skills and experience to undertake a revaluation as outlined in the RTWR and to have an independent sign-off of the valuation by a registered Philippine appraisal company, it has selected an Independent Expert which is comprised of an accredited local appraisal company (Cuervo Appraisers) and an offshore engineering firm (Sinclair Knight Merz Pty Ltd) who have the required skills and expertise in revaluing transmission assets under similar performance based regulatory arrangements in the Philippines and other jurisdictions. The ERC recognizes NGCP for providing a list of suitable Independent Experts in its submission of April 2, 2009, from which the ERC has selected these Independent Experts for valuation purposes in a joint venture between SKM and Cuervo so that the valuation can proceed according to the RTWR. The ERC notes this list may provide other Independent Experts for the process as it unfolds.


Page 22

3

CHAPTER 3

CAPITAL EXPENDITURE FORECASTS

3.1 General Basis of Capital Expenditure Forecasts 3.1.1 Section 4.10 of the RTWR outlines the data requirements on the capital

expenditure forecasts that NGCP must deliver to the ERC. Section 5.10.1 of the RTWR requires that these techniques also be used for the Third Regulatory Period. These forecasts are to be based on the economically efficient capital expenditure requirements to meet the forecast demand over the Third Regulatory Period. In particular the economic efficiency of the forecasts should be judged against the general principles provided in Section 4.4.1 of the RTWR, and the declaration of policy in Section 2 of the EPIRA.

3.1.2 Section 4.10.4 of the RTWR also provides for the ERC to rely on an Independent Expert to review the capital expenditure forecasts and its supporting documentation. The Independent Expert is to assess the capital expenditure forecasts to ensure they are:

(a) Represented fairly in discrete projects where required;

(b) Based on best available prices obtainable from international markets;

(c) Reasonably efficient from design and implementation point of view;

(d) Sufficient to support forecast growth in customer connections, co-incident peak demand and energy delivered;

(e) Sufficient to allow the regulated entity to achieve or exceed the applicable target levels of performance specified by the ERC.

3.1.3 In judging whether the forecast capital expenditure is reasonably efficient from a design and implementation point of view, the ERC requires that the Independent Expert use similar principles and approaches as is required for optimization and revaluation of the RAB. Specifically the processes outlined in paragraphs 2.4 above and in Figure 2.1 above should be employed as a minimum to ensure the forecast capital expenditure program is reasonably efficient, and hence could be recommended by the Independent Expert for inclusion into the rolled-forward asset base which underpins the building block analysis and hence NGCP’s revenue requirement.

3.2 Capital Expenditure Forecast Process & Justification 3.2.1 NGCP is required to document and justify the major capital expenditure

projects that it plans to undertake. Major projects are defined in Section 4.10.1 of the RTWR where the capital expenditure for that project is greater


Page 23

than or equal to PhP50million. In order to provide an overview of the prime reasons for each major project, the projects are classified into groups as provided in Figure 3.1.

Project List

>=PhP 50m ?

Classify into:

A) Load growth B) Non-load growth by: i) Network

ii) Non-networkiii) Network control, safety or meteringiv) Other

Yes

And by:

A) Replacemnet B) Refurbishment C) New assets i) Shared

ii) Connections D) Year of forecast exp.

Classify into:

A) Network B) Non-network C) Other

No

Categorise Annual Capital Expenditure

Figure 3.1 : Project Classification

3.2.2 The ERC sought comments on the classifications to be used to assist summarization and analysis of NGCP’s capital expenditure forecast. In its submission dated April 2, 2009, NGCP has indicated that it will classify assets within its capital expenditure program using the same classifications of assets it provides for the RAB.

3.2.3 In response to this comment, the ERC again emphasizes that the forecast capital expenditure plan proposed by NGCP in its application, must include sufficient information describing each primary project, its purpose, its timing and its classification under Figure 3.1 which is a summary of the


Page 24

requirements in Section 4.10.2 of the RTWR, so that the ERC and/or its Independent Expert, can analyze the economic efficiency of the proposed forecast capital expenditure programs. To emphasize this point to NGCP, the following paragraphs describe the process used by the ERC in analyzing the capital expenditure program for the Second Regulatory Period.

3.2.4 In order to undertake this analysis TransCo was required to deliver the information on its projects using the data template in Figure 3.2, which encloses an example. The ERC believes the same template should be used for the Third Regulatory Period, but shall take submissions from NGCP on alternative approaches, which it shall consider with the assistance of the Independent Expert, should one be appointed.

National Grid Corporation of the Philippines CY 2010 – 2014 Capital Expenditure Forecast Capex Project Review Summary Project Details:

Name Leyte-Luzon HVDC Interconnection Project

Description Construction of 468 km Naga-Sorsogon CTS overhead line, 23km Sorsogon-Ormoc submarine cable, 25km AC-interconnection, and HVDC converter stations

Date Commissioned

1997

Project classification:

Rank COMPLETED (Ongoing; 1st Priority; 2nd Priority)

Project Driver Classification

Load Growth (Load Growth; Network non-growth; network control / safety / metering; non network)

Project Type Classification

0% Replacement 100% New Assets

(Replacement; Refurbishment; New Assets)

Year of Capex 2010 2011 2012 2013 2014

Amount Php million 15.5 22.0 25.2 5.0 0.5 Project Recommendation: (Summary of Decision by ERC)

Capex Project Classification : Approved Fully Approved at X% Not Approved

Recommendation : [y/n] [ ] % [y/n]

Flowchart Path [ describe the path through the capex analysis flowchart and relevant decision points ]

Primary Reason(s) for Decision

[ to be inserted ]

Other Comments [ only if not covered in analysis or recommendation ]

. Figure 3.2 : Capex Project Information Template


Page 25

All Capex Projects Filed under Reset

Network asset ?

Y

Check classification as should fall

above

N

Network control, safety or metering asset ?

NTask 1

Y

Non – network asset ?

N

Y

Replacement ?Age

>= Life less 15 y ?

Y

Y

Reject Capex

N

N

Refurbish ?

N

Newasset ?

Y

Better Reliability, Extend

life or get to life ?

N

Y

Connectionasset ?

Y

Y

N

N-1Justific-ation ?

Y

Does SKM report acceptand/or agree with

N-1 ?

Y

Y

N

Doesrating exceed15 y require-

ment?

N

N

YInclude assets

in optimized networkat reduced rating

Include all in optimized network

Is line or substation

required now?

N

Y

Force Majeure Damage?

N

Y

Task 2

Task 2

Is cost>=P50m?

Y

N

Task 3Grouped

Capex projects?

N

Y

Can project be delayed ?

Y

N

Contributedasset ?

Sharedasset ?

Sub-Transasset ?N

NN

To beSold >=

5y ?Y

Y

YN

. Figure 3.3 : Technical Review of Large Projects


Page 26

Task 1

Are cost benchmarks

available?

Y

N

Is justification provided?

Y

N

Is costReasonable?

Is cost>=P50m?

Is justification provided?

Rejectcapex

Is justificationReasonable?

Y

N

Y

N

Y

Y

N

Optimize cost to benchmark

N

Optimize cost to reasonable

levelIs cost

<= Benchmark?

N

Y

Task 2

Accept capex at optimized or

submitted level

Figure 3.4 : Cost Optimization of Large Projects

3.2.5 The Figures above and below indicate the process used by the ERC to review the capital expenditure forecasts developed by TransCo during the regulatory reset for the Second Regulatory Period. The analysis was undertaken for the following project types:

(a) For large projects greater than of equal to Php50 million, the processes in Figure 3.3 where followed, and then the processes in Figure 3.4 were followed (refer to the information required on the left hand track of Figure 3.1).

(b) For large projects less than Php50 million, the processes in Figure 3.5 where followed (refer to the information required on the right hand track of Figure 3.1).


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Network asset ? Y

Check classification as should fall

above

N

Network control, safety or metering asset ?

N

Non – network asset ?

N

Replacement ?Age

>= Life less 15 y ?

Y

N

N

Refurbish ?

N

Newasset ?

YExtend

life or get tolife ?

N

Y

To be sold >=

5y ?Y Y

N

Y

N

Isexpense timing

reasonable ?

Y

Y

Task 3

AcceptCapex

Is justification reasonable

?

Y

UngroupGrouped

Capexprojects

B

Y

A

B

RejectCapex

NWould

timing delaywork ?

AcceptCapex with

delay

N

Y

Sub-Transasset ?

A

B

Y

Y

SharedAsset ?

N

YN

ConnectionAsset ?

N

Contributed Asset ?

Y

Y

N

N

Figure 3.5 : Review and Cost Optimization of Small Projects

3.2.6 The ERC has not firmly decided to adopt this same approach so will seek comments from NGCP in its application, and it particular review simplified


Page 28

approaches to analyze the projects with capital expenditure of less than Php50 million.

3.3 Actual Capital Expenditure for 2005 to 2009 3.3.1 NGCP is required to provide the historical capital expenditure information

for the period 2005 to 2009 inclusive, noting that the time table for delivery is part way into the 2009 year. The data for 2009 will need to be part actual and part budgeted information.

3.3.2 NGCP is required to deliver the actual capital expenditure summaries for capital projects greater than or equal to Php50 million, on a project by project basis in the same Excel spreadsheet format as was provided to the ERC for approval for of those capital expenditure projects. The general format is provided again at Appendix B.

3.3.3 Justification for expenditures greater than forecast need to be provided before the ERC (following consideration of the recommendations of the Independent Expert) shall include either the full actual capital expenditure (where additional costs are justified and outside the control of NGCP), part of the additional actual capital expenditure above forecast (where only part of the additional costs are justified and outside the control of NGCP), or at the forecast capital expenditure forecasts where the additional costs appear be controllable and were (or should have been) forecast at the point of application for approval during the regulatory reset for the Second Regulatory Period. Unjustified additional capital expenditure above that forecast shall be considered economically inefficient and hence imprudent, and shall be excluded from the RAB in developing the rolled-forward asset base. The analysis shall also feed the efficiency carryover analysis undertaken by the ERC in accordance with Article IX of the RTWR.

3.3.4 Justification for expenditures less than forecast need to be provided before the ERC (following consideration of the recommendations of the Independent Expert) shall include the cost reduction as an efficiency saving which can be claimed by NGCP in its revenue path for the Third Regulatory Period. The ERC will have particular focus on ensuring whether the forecast project benefits, functionality and capacity have been delivered at a lower efficient cost, or the under expenditure is itself imprudent. Unjustified under expenditure below that forecast shall be considered imprudent and shall be excluded from the efficiency savings that can be claimed in the efficiency carryover analysis undertaken by the ERC in accordance with Article IX of the RTWR. Where functionality and capacity are provided but at less than forecast, but can be justified as a reasonable efficiency saving given a 15 year planning horizon, the ERC shall consider the allowance of this efficiency saving in the efficiency carryover analysis.

3.3.5 It is possible that some Forecast capital expenditure projects have not progressed as forecast. The capital expenditure forecasts for these projects which were allowed into the revenue path may have been used for


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alternative higher-priority capital projects that were subsequently approved by the ERC , and can be considered for inclusion into the RAB where the ERC decides that those previously approved capital expenditure which have progressed during the Second Regulatory Period are efficient and prudent. The approach to examine these new capital expenditure projects shall be on the same basis as new forecast capital expenditure projects. NGCP will need to justify that the project is of efficient capacity and cost. Optimization principles will still apply.

3.3.6 The NGCP submission summarises Meralco’s suggestion that paragraph 3.3.3 above only be applied when actual expenditures are greater than 110% of the forecast, and paragraph 3.3.4 above only be applied when expenditures are at les than 90% of the forecast. While this has some attraction in reducing the workload of both NGCP and the ERC, it is currently preferred that all of the seventy-four (74) primary large projects filed for the 2006 regulatory reset, be review in detail, at least for this regulatory reset for the Third Regulatory Period.

3.3.7 NGCP goes further and suggests justification need only be required where capital expenditures are greater than forecast and that there is not an automatic omission of recovery of the over-run where it can be justified that this is reasonable. NGCP further provides Annex C of its submission dated April 2, 2009 which is a commentary by LECG over the prudency test to be applied by the ERC under Article IX of the RTWR. In summary, LECG propose that NGCP prepare an ex-post forecast for the 2005 to 2010 period which incorporates what was known to have occurred during that period so that a forecast which excludes external or uncontrollable effects can be produced to be the benchmark used in Article IX of the RTWR. While not committing at this time to the exact methodology it will adopt in its Draft Determination, the ERC believes the approach suggested by LECG has merit and should be included with the NGCP filing in December 2009.

3.3.8 In addition the ERC flags to NGCP that some of the small projects filed for the 2006 regulatory reset, will be review in detail because of their apparent impact on the performance of the network in the interim period. For example, the purchase of spare transformer and new meters will be a particular focus because of the impact on congestion a lack of transformer spares has had on the network, and because of complaints relating to inoperable or faulty market and customer meters. The ERC shall fall to NGCP the small projects in question through a separate correspondence to be provided by the end of August 2009, and indicates this shall be an initial focus which may be added to following filing of NGCP’s application.

3.4 Capital Expenditure Forecast Categorisation 3.4.1 NGCP is required to provide its capital expenditure forecast broken down

into the asset categories required for the opening re-valued RAB, subject to the additional line items being considered for inclusion in the current


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amendment process for the RTWR. The categories are outlined in Section 4.6.5 of the RTWR and additional categories are required as per paragraph 2.5.1 of this Position Paper.

3.4.2 Appendix B provides the templates for the capital expenditure forecasts which need to be delivered by NGCP to the ERC. One of the prime deliverables is the summary sheet of the total capital expenditures in nominal peso. See also Figure B.1 which summarizes the calculation flow. The spreadsheets as delivered to the ERC with the NGCP application need to be fully operational and have all formulae intact and working accurately. The spreadsheets need to be delivered in soft and hard copy form.

3.5 Isolation of CPI and Foreign Exchange Impacts 3.5.1 The ERC needs the capital expenditure forecasts broken down to isolate the

CPI from the Philippines and USA, and the Peso/US$ exchange rate from the capital expenditures because in modelling the MAR these forecast assumptions need to dynamically modelled. In addition these forecasts are also used as potential trigger points for the reassessment of the X factor or for the reopening of the previous regulatory settings.

3.5.2 The ERC sought comment on the methodology to convert forecast US$ purchases into Peso amounts and application of the Philippines and US CPI, to provide a forecast of the landed cost in peso. Also, the ERC sought comment on the forecasts of the CPI from the Philippines and USA, and the Peso/US$ exchange rate to be used for modelling purposes over the Second Regulatory Period. Submissions received propose to use the forecasts provided by the Economist Intelligence Unit (EIU) as has been used previously for the regulatory reset for the Second Regulatory Period and for the reset processes for the Distribution Utilities. The ERC will use the EIU forecasts of these parameters for the Third Regulatory Period for reasons including that it is a consistent forecast for all parameters required, it comes from a source independent of the industry and primary stakeholders, and are forecasts based on detailed macroeconomic modelling of the global economy.

3.6 Asset Lives for Forecast Capital Expenditure

3.6.1 NGCP provided modified economic lives for its assets in Annex D of its April 2, 2009 submission. These are reproduced in the following Table 3.1. At present while expressing the view economic lives of assets should change, NGCP has not provided a strong justification in support of any change.


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Category Description

SKM / Cuervo Life 2nd Reset

(years)

NGCP Proposed Life

3rd Reset

(years)

Notes

Transmission Lines

Lattice steel tower line 50 50

Wood pole line 50 25

Concrete pole line 50 See Note 3

Steel pole line 50 See Note 3

Power Cables

Submarine HVDC 50 50

Submarine HVAC 50 50

Underground HVAC 50 50

Outdoor Substations – MEAs

Transformers 500 kV 45 45 N-1 security

Transformers 230 kV 35 Without N-1 security, Note 3

45 With N-1 security, Note 3

Transformers 115 kV 35 Without N-1 security, Note 3

45 With N-1 security, Note 3

Reactors 35 See Note 3

Capacitor banks 40 See Note 3

Outdoor switchbays 40 40 500 kV,230 kV, 138/115 kV, 69 kV outdoor assemblies, Note 1

Substation establishment assets

50 50 See Note 2

Outdoor Substations – individual equipment

Circuit breakers 40 40 500 kV, 230 kV, 138/115 kV, 69 kV

Indoor GIS Substations

500 kV GIS switchbay 40 45



Substations Secondary

Protective relays and controls

15 15

Metering equipment 30 30

RTUs, SCADA systems 15 15

Communications

OPGW links 50 See Note 3

PLC links 35 See Note 3

Radio links 15 15


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Category Description

SKM / Cuervo Life 2nd Reset

(years)

NGCP Proposed Life

3rd Reset

(years)

Notes

System Operations

15 15

Notes:

1. A switchgear bay includes the primary equipment, buswork, foundations, equipment supports and other structures, protective and control equipment and cabling directly associated with the bay.

2. Substation establishment assets include earthworks, roads, fencing, drainage, earth grid, auxiliary AC and DC power supplies, batteries, cabling not specific to a bay, auxiliary mechanical services, protection and control equipment not specific to a bay.

3. SKM/Cuervo were not explicit on these in 2nd Regulatory Reset

Table 3. : Economic Lives of Assets for Second Regulatory Period and as Proposed by NGCP for the Third Regulatory Period

3.6.2 As such, the asset lives the ERC shall use for the roll-forward RAB analysis shall be the same for each assets category as is used for the re-valued opening asset base, and as was used in the regulatory reset for the Second Regulatory Period, unless the Independent Expert recommends otherwise. The Independent Expert is to provide advice to the ERC on the economic life of each asset category to assist in the calculation of the optimised depreciated replacement cost and also for the depreciated indexed cost of the RAB at the end of each year of the Third Regulatory Period. The asset life for regulatory purposes should be the Independent Expert’s current estimate of the economically efficient life of that asset category (relevant for the valuation methodology under consideration), based on their design and condition monitoring experience and the reasonable balance between operating & maintenance expenditure and life-time replacement expenditure. Such experience adjusted to account for the differences in environment experienced by transmission network assets within the Philippines.

3.6.3 Where a change in the economic life of a particular asset class or category results in a wind-fall gain or loss, the ERC may examine the impact of this change on the re-valued RAB. Where the ERC determines a wind-fall gain to be excessive it may take the option to reduce this wind-fall gain.

3.7 Load Forecasts 3.7.1 The ERC received a letter from TransCo dated October 20, 2008 requesting

guidance on which load forecasts the ERC would use to assess the capital expenditure forecasts for the Third Regulatory Period. In its response the


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ERC indicated that it saw “merit in adopting the [Power Development Plan] PDP as official reference plan of the [Transmission Development Plan] TDP. The Commission believes that the TDP should be aligned with the country’s over-all energy plan for seamless integration into the Philippine Energy Plan. It should be noted that in the Final Determination for the Second Regulatory Period, the Commission adopted the DOE forecast”. The ERC notes that the TDP has previously been based on the system coincident peak demand on an island basis (effectively a sub-Grid and regional basis) and this is an important planning tool when new transmission projects are considered for inclusion in the plan. Further that TransCo also prepares a non-coincident peak demand forecast at a substation and transformer level which is at a more discrete level but is related to the sub-Grid and regional level forecast of system coincident peak demand.

3.7.2 During the Second Regulatory Reset the ERC utilised both forecasts for its review and assessment of the capital expenditure forecasts. The ERC envisages that with the assistance of the Independent Expert appointed to assist with the capital expenditure review, it will again utilize the TDP coincident peak demand forecasts to assist in assessing the priority of transmission projects, while at the same time utilising the more detailed non-coincident peak demand forecasts at the substation and transformer level as one input to assist with the assessment of the detail of the individual primary projects for prudence from a capacity, congestion and voltage point of view.

3.8 Data Requirements 3.8.1 The data requirements for capital expenditure forecasts have been

documented in Article VI of the TWRG dated May 29, 2003. Additional guidance to NGCP and to an Independent Expert which may be appointed pursuant to Article XIV of the RTWR, are provided in this Chapter 3. The ERC notes the Independent Expert may need access to more detailed and different information to fulfil its responsibilities and that NGCP should endeavour to meet the information and data needs of the Independent Expert wherever possible.

3.9 Reconciliation to Financial Statements 3.9.1 NGCP is required to provide the actual capital expenditure for the

period 2005 to 2009 as indicated in paragraph 3.3.1 above. NGCP is also required to provide in its application a reconciliation of the actual capital expenditure to the construction work in progress as reported in its audited financial statements for each of the years which are complete prior to its application date, with a statement from its auditors to the reasonableness of this reconciliation, or where this is not available a written statement from a senior executive of TransCo or NGCP, or as otherwise approved by the ERC.


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4

CHAPTER 4

OPERATING & MAINTENANCE EXPENDITURE FORECASTS

4.1 General Basis of Operating & Maintenance Expenditure Forecasts 4.1.1 Section 4.11 of the RTWR outlines the data requirements for the operating

& maintenance expenditure forecasts that NGCP must deliver to the ERC. Section 5.11.1 of the RTWR requires that these techniques also be used for the Third Regulatory Period. These forecasts need to be accompanied by a justification against each expenditure category (see below) as to why the forecast expenditures are necessary, and are of reasonable magnitude, for example by benchmarking to other transmission companies or distribution utilities. Improvements in efficiency over the Third Regulatory Period should be demonstrated by the forecasts. In particular the magnitude of the forecasts should be judged against the general principles provided in Section 4.4.1 of the RTWR, and the declaration of policy in Section 2 of the EPIRA.

4.1.2 Section 4.11.4 of the RTWR also provides for the ERC to rely on an Independent Expert to review the operating & maintenance expenditure forecasts and its supporting documentation. The Independent Expert is to assess the operating & maintenance expenditure forecasts to ensure they are:

(a) Reasonably efficient (against similar benchmarks);

(b) Sufficient to support forecast growth in customer connections, co-incident peak demand and energy delivered;

(c) Sufficient to allow the regulated entity to achieve or exceed the applicable target levels of performance specified by the ERC; and

(d) Reasonable with respect to recovery of bad debts and a strategy for improving debt collections is provided.

4.2 Operating & Maintenance Expenditure Forecast Categorisation

4.2.1 NGCP is required to provide its operating & maintenance expenditure forecast broken down into the expenditure categories provided in Section 4.11.1 of the RTWR.

4.2.2 Given the complexity of analyzing expenditures which are of low materiality, The ERC shall not require detailed review of the “Other” operating & maintenance expenditure category, provided the level of this expenditure is less than 5% of the total forecast operating & maintenance expenditure in any forecast year.

4.2.3 Appendix C provides the templates for the operating & maintenance expenditure forecasts which need to be delivered by NGCP to the ERC.


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One of the prime deliverables is the summary sheet of the total operating & maintenance expenditures in nominal peso. See also Figure C.1 which summarizes the calculation flow.

4.2.4 Additional comments on the proposed approach to estimating, reviewing and approving efficient operating & maintenance expenditure forecasts, and on the templates by which the forecasts need to be delivered, were not received by the ERC. As such there are no proposed changes to the information templates provided at Appendix C.

4.3 Isolation of CPI and Foreign Exchange Impacts 4.3.1 The ERC needs the operating & maintenance expenditure forecasts broken

down to isolate the CPI from the Philippines and USA, and the Peso/US$ exchange rate from the operating & maintenance expenditures because in modelling the MAR these forecast assumptions need to dynamically modelled. In addition these forecasts are also used as potential trigger points for the reassessment of the X factor or for the reopening of the previous regulatory settings.

4.3.2 The ERC sought comment on the methodology to convert forecast US$ purchases into Peso amounts and application of the Philippines and US CPI, to provide a forecast of the landed cost in peso. Also, the ERC sought comment on the forecasts of the CPI from the Philippines and USA, and the Peso/US$ exchange rate to be used for modelling purposes over the Second Regulatory Period. Submissions received propose to use the forecasts provided by the Economist Intelligence Unit (EIU) as has been used previously for the regulatory reset for the Second Regulatory Period and for the reset processes for the Distribution Utilities. The ERC will use the EIU forecasts of these parameters for the Third Regulatory Period for reasons including that it is a consistent forecast for all parameters required, it comes from a source independent of the industry and primary stakeholders, and are forecasts based on detailed macroeconomic modelling of the global economy.

4.4 Actual Operating Expenditure for 2005 to 2009 4.4.1 TransCo in consultation with NGCP, is required to provide the historical

operating expenditure information for the period 2005 to 2009 inclusive, noting that the time table for delivery is part way into the 2009 year. The data for 2009 will need to be part actual and part budgeted information.

4.4.2 Justification for expenditures greater than forecast need to be provided before the ERC (following consideration of the recommendations of the Independent Expert) shall include either the full actual operating expenditure (where additional costs are justified and outside the control of TransCo and/or NGCP), part of the additional actual operating expenditure above forecast (where only part of the additional costs are justified and outside the control of TransCo and/or NGCP), or at the forecast operating


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expenditure forecasts where the additional costs appear be controllable and were (or should have been) forecast at the point of application for approval during the regulatory reset for the Second Regulatory Period. Unjustified additional operating expenditure above that forecast shall be considered economically inefficient and hence imprudent, and shall be included into the efficiency carryover analysis undertaken by the ERC as an offset to other efficiency gains for the Second Regulatory Period in accordance with Article IX of the RTWR.

4.4.3 Justification for expenditures less than forecast need to be provided before the ERC (following consideration of the recommendations of the Independent Expert) shall include the cost reduction as an efficiency saving which can be claimed by NGCP in its revenue path for the Third Regulatory Period. The ERC will have particular focus on ensuring whether the forecast operating expenditures have been delivered without detriment to the PIS measures and hence shall be considered as prudent expenditure. Where reduced expenditures have occurred but PIS measures have been maintained and TransCo in consultation with NGCP can justify its approach as a reasonable efficiency saving, the ERC shall consider the allowance of this efficiency saving in the efficiency carryover analysis.

4.4.4 The commentary by LECG over the capital expenditure prudency test provided in Annex C of the NGCP submission dated April 2, 2009 (see paragraph 3.3.7 and 3.3.8 above) mentions the operating and maintenance efficiency test but provides substantive additional proposals over how the efficiency carry-over should be applied by the ERC under Article IX of the RTWR. The ERC shall consider the justifications that are included in the NGCP application before developing its views further on whether and how to adjust the operating and maintenance expenditure forecasts approved by the ERC in its Final Determination of June 13, 2006, before applying the provisions of Article IX of the RTWR.

4.5 Inclusion of Benefits into Operating and Maintenance Costs

4.5.1 The ERC is concerned that in reviewing the operating and maintenance costs from both an historical point of view over the Second Regulatory Period and a forecast point of view over the Third Regulatory Period, it shall focus on the reasonableness of the retirement costs and benefits for the staff of TransCo / NGCP. The ERC shall focus on allowing a reasonable but not excessive pass through of these costs into the building block for the NGCP revenue requirement.

4.6 Reconciliation to Financial Statements

4.6.1 TransCo in consultation with NGCP is required to provide the actual operating and maintenance expenditure for the period 2005 to 2009 as indicated in paragraph 4.4.1 above. NGCP is also required to provide in its application a reconciliation of the actual operating and maintenance expenditure to the audited financial statements for each of the years which


Page 37

are complete prior to its application date, with a statement from its auditors to the reasonableness of this reconciliation, or where this is not available a written statement from a senior executive of TransCo or NGCP, or as otherwise approved by the ERC.


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5

CHAPTER 5

INCOME TAX AND OTHER TAXES, LEVIES AND DUTIES

5.1 General Comments on Tax Issues 5.1.1 The RTWR has been set up to provide regulatory certainty to TransCo and

its Concessionaire, currently NGCP. Now that the concession process has been finalized, there is more clarity surrounding the treatment of corporate income tax and other taxes, levies and duties which the ERC should apply in its administration of transmission rates under the RTWR. NGCP is a franchise holder and is required to pay a franchise tax, under RA 9511.

5.1.2 The primary assumption made by the ERC in developing the TWRG (the predecessor of the RTWR) was that the regulatory arrangements set the revenue cap for the combined TransCo/Concessionaire irrespective of the eventual commercial arrangements set out in the Concession Agreement and in the Franchise Agreement.

5.1.3 In this sense whether the assets are owned by TransCo or the Concessionaire, or whether the revenues are collected by either organization, the ERC shall treat them as the one related entity for regulatory purposes. The effect of this is that the structure of the Concession Agreement does not alter the amount of reasonable costs that can be recovered from customers receiving the Regulated Transmission Services.

5.1.4 There are a number of uncertainties relating to taxes which the ERC needs to consider in its analysis of reasonable costs leading up to the Third Regulatory Period. Through the consultation process leading from publication of the Issues Paper the ERC currently understands that:

(a) TransCo did pay some corporate income tax during the latter part of the Second Regulatory Period, up until NGCP took over the concession (giving rise to the need for analysis under Section 4.12 of the RTWR);

(b) NGCP has and will continue to pay franchise tax under RA 9511 from the time it took over the concession till the end of the Second Regulatory Period (giving rise to the question of whether this unforecast expenditure is recoverable), but will not be paying corporate income tax; and

(c) NGCP will continue to pay franchise tax under RA 9511 for the whole of the Third Regulatory Period, but will not be paying corporate income tax.


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5.1.5 When drafted the RTWR assumed that TransCo/Concessionaire would be paying either or both a franchise tax and corporate income tax to the Philippines government. The ability to accommodate these types of payments by TransCo and/or its Concessionaire was provided because of the considerable uncertainty which existed regarding government policy and developing jurisprudence on such matters. The ERC is of the view that the RTWR will be able to accommodate the various analyses required to accord with the facts outlined paragraph 5.1.4 above.

5.1.6 The ERC has previously indicated that where NGCP / Concessionaire is exempt from various corporate income tax, or other taxes, levies and duties (including franchise tax) due to either the franchise arrangements or the concession arrangements, these should also be excluded from the forecast costs provided to the ERC once these facts are known. Nonetheless, the RTWR was drafted to allow recovery of corporate income tax in the rates, but on a regulatory period basis (ie: every five years) have this recovery adjusted to only allow the remit to the Bureau of Internal Revenue to be recovered, as required under Section 5.12.2 of the RTWR. The ERC understands TransCo did pay corporate income tax during part of the Second Regulatory Period, but this condition does not continue for NGCP. The effect of this is that 5.12.2 shall require an increase in the revenue cap for the Third Regulatory Period.

5.1.7 NGCP has indicated that the franchise tax it is required to pay should become a recoverable cost and would be included as a reasonable cost for recovery in the forecasts used under the RTWR. The RTWR provisions suggest that the treatment of franchise tax could be included within the NGCP application (refer to Sections 4.5.7 and 4.11.2 in relation to taxes other than corporate income tax) , and hence be subject to the further public hearing process prior to the ERC making its Draft and Final Determinations on how such costs shall be treated. The following approaches are suggested by the RTWR, and require no modification of the sections within the RTWR:

(a) For the franchise tax paid under paragraph 5.1.4 (b) above, these costs would need to be adjusted in the forecasts used to assess the comparison between the forecast and actual expenditures for the Second Regulatory Period provided in Article IX of the RTWR relating to the efficiency carry over analysis. Much of the franchise tax paid shall be known and should be able to be justified from receipts available form the BIR upon payment. Some budget numbers may need to be included as a reasonable estimate of the franchise tax for the 2010 financial year.

(b) For the franchise tax paid under paragraph 5.1.4 (c) above, these costs could be analyzed on a forecast basis as suggested by NGCP in the submission matrix on franchise tax it submitted on April, 17,


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2009, of as otherwise approved by the ERC during the regulatory reset process.

5.1.8 The ERC does not accept the analysis suggested by NGCP in the submission matrix on franchise tax it submitted on April, 17, 2009. The approach does not appear to match the ERC’s current understanding of the operation of RA 9511 on “gross income”. The ERC requires NGCP to use a methodology which has the franchise tax as a percentage of the gross income to match the requirements of RA 9511 on a forecast basis.

5.2 Isolation of Tax Impacts (Other than Corporate Income Tax) 5.2.1 Section 4.11.2 of the RTWR requires NGCP to separately identify both

historical and forecast payments of taxes, levies and duties (other than corporate income tax), see Section4.11.2 of the RTWR. Where these can be separately identified they should also be categorised on the same basis as the operating & maintenance expenditure forecasts. The historical and forecast payments of taxes, levies and duties (other than corporate income tax) must not include any double counting of payments. Justification of the magnitude of the forecast payments of taxes, levies and duties (other than corporate income tax) should also be provided. Where NGCP is exempt from various taxes, levies and duties (other than corporate income tax) due to either its franchise arrangements or the eventual concession arrangements, these should also be excluded from the forecasts provided to the ERC.

5.2.2 The primary issue for the ERC in examining taxes, levies and duties (other than corporate income tax), is the franchise tax position of NGCP to be carried into the Third Regulatory Period. In particular the arrangements for NGCP under RA 9511 will need to be considered by the ERC it its forward analysis of the revenue cap for the Third Regulatory Period.

5.2.3 The templates for reporting tax payments (other than corporate income tax) are provided in Appendix C. It includes historical information on tax payments (other than corporate income tax) and in particular franchise tax. To the extent possible, NGCP must be able to prove to the ERC that these taxes have been paid.

5.3 Under and Over Recovery of Franchise Tax 5.3.1 Currently the RTWR does not contemplate the need to have a specific under

/ over recovery mechanism for taxes, levies and duties (other than corporate income tax), other than exists in the overall factor of Kt in the revenue cap formula provided in Section 4.2.1 of the RTWR.

5.3.2 Given the potentially large value of the franchise tax to be paid by NGCP, the ERC is of the initial view that a separate under / over recovery mechanism or calculation, similar to that employed for corporate income tax in Section 4.12.4 of the RTWR, should also be used for the franchise tax so


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that the franchise tax recovered is matched to the franchise tax paid including the time value of money adjustment for each regulatory period.

5.3.3 Any adjustment for franchise tax paid / payable would then feed into the building block for the Subsequent Regulatory Period and be subject to the normal under / over recovery mechanism of Kt during that regulatory period.

5.3.4 The ERC requires NGCP to include in its filing for the Third Regulatory Period a formula or approach to allow the RTWR to be further amended to accommodate the over / under recovery adjustment every five years, and as determined during each regulatory reset.

5.4 Historical payments of Corporate Income Tax 5.4.1 In Section 5.12.2 of the RTWR, an income tax adjustment is undertaken to

ensure that any difference between the recovery of corporate income tax and the amount actually paid to the Bureau of Internal Revenue, is adjusted within the revenues allowed to be recovered by NGCP. The adjustment seeks to correct any difference from actual income tax payments in the Second Regulatory Period within the Third Regulatory Period, including the impact of the time-value-of-money.

5.4.2 To achieve this calculation, the ERC requires TransCo in consultation with NGCP to separately identify historical payments of income taxes which specifically relate to the Transmission Services provided using Regulated Transmission Assets. Justification for the income tax amounts claimed in NGCP’s application may be needed where the income tax paid partially relates to unregulated revenues. Section 4.12.5 requires TransCo in consultation with NGCP to verify such payments by returns from the Bureau of Internal Revenue and documented evidence of payment from Authorized Agent Banks. Clearly the assistance of TransCo shall be required to allow this documentation to be prepared. Where NGCP cannot verify these payments, the ERC will assume NGCP has made zero income tax payments.

5.4.3 The primary issues for the ERC in examining the corporate income tax position of NGCP to be carried into the Third Regulatory Period, relate to whether:

(a) TransCo was legally separated from the National Power Corporation (NPC), and whether from that date corporate income tax was required to be paid;

(b) TransCo and/or the Concessionaire was required to pay corporate income tax during the Second Regulatory Period and/or will be required to pay corporate income tax during the Third Regulatory Period (the provisions of RA 9511 apply);

(c) TransCo has paid tax (and assuming this can be reasonably isolated from the related NPC activities), and TransCo is in a position to have


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its payments certified by an independent external auditor as required under Section 4.12.5 (b), or where this is not available a written statement from a senior executive of TransCo or NGCP, or as otherwise approved by the ERC to cover the situation where the COA or NGCP’s independent external auditor is unable to provide an audit statement;

(d) Any corporate income tax losses should be carried forward by NGCP into the Third Regulatory Period but only where corporate income tax has been paid in the Second Regulatory Period (the ERC understands no such losses have occurred); and

(e) The ERC should assume the corporate income tax to be paid by NGCP should be assumed to be zero for the Third Regulatory period, in accordance with RA 9511.

5.4.4 The ERC notes it has already determined that the recovery of corporate income tax adjusted for the actual corporate income tax paid, is a reasonable cost which should be recovered by TransCo and/or the Concessionaire and this methodology forms part of an alternative form of internationally-accepted rate-setting methodology (see Section 43(f) of the EPIRA and Rule 15, Section 5(a) of the IRR).

5.5 Data Requirements 5.5.1 The data template requirements for tax payments (other than corporate tax

payments) are outlined in Appendix C. The data template requirements for corporate tax payments are outlined in Appendix D. The requirement to provide justification for the level of tax payments, and verification of actual payments is provided above and in Section 4.11.6, 4.12.5 and 5.12 of the RTWR.


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6

CHAPTER 6

WEIGHTED AVERAGE COST OF CAPITAL

6.1 Overview 6.1.1 The weighted average cost of capital (WACC) to be used for regulatory

purposes is estimated using the approach outlined in Section 4.9 of the RTWR. The regulatory WACC to be used for the purposes of setting the revenue cap for NGCP, is designed to be an estimate of a reasonable industry average WACC which is set in a manner to encourage investment in electricity transmission assets without being excessive. The ERC is aware that the recent and continuing global financial crisis (GFC) may be having an effect on the financial markets which distorts the market data upon which WACC estimates are normally based. While the ERC will need to update its estimate of the regulatory WACC closer to its Draft Determination, it will review any distortions in the market data at that time due to the GFC and move to adjust its approach or use alternative data sources where the data it would normally rely upon looks abnormal and/or creates unreasonable distortions in the outcome.

6.1.2 It is extremely important to recognize that the Return on Rate Base (RORB) and the WACC are NOT comparable financial measures. RORB is the result of the comparing a net revenue measurement against the asset base employed and can be classified as a financial statement measurement, while the WACC is a measure of the cost of debt and cost of equity required to fund the business and can be classified as a cash flow measurement.

6.1.3 The ERC intends to continue with the WACC methodology provided in the TWRG, as amended to the RTWR and taking into account the effects of the new tax arrangements for NGCP in RA 9511, dated December 1, 2008. However, it will look in more detail during the regulatory reset process at two adjustments to the approach which have been suggested previously and again in submissions to the Issues Paper.

6.1.4 The first suggestion which was included in the Issues Paper was in response to the developments in consideration of WACC for the PBR for the Distribution Utilities for the entry groups from A to C has indicated the potential for the need to consider whether:

(a) Input values derived using average market data over longer periods of time are more representative of the cost of capital for NGCP than reliance on the spot market measures which were preferred for the regulatory reset for the Second Regulatory Period, particularly in light of the effects of the credit crisis currently being


Page 44

experienced in world markets and the distortions in market returns for risk resulting from low liquidity; and

(b) Consideration of the setting of the corporate income tax building block to zero requires that input values for the WACC methodology should be selected from one or other end of the range of market values found for each WACC parameter.

6.1.5 The second suggestion comes from Annex F in the NGCP submission from April 2, 2009, relating to the calculation of the capital asset pricing model (CAPM) and specifically in relation to the formulae used for delevering of equity beta from companies in other countries, and the relevering to estimate the equity beta to use for NGCP. NGCP, relying on analysis provided during the previous regulatory reset by expert advisor, Professor Tony van Zijl, is advocating an additional factor in these formulae to accommodates the differences between the tax rates on dividend income (an equity return) and on interest income (a return on debt). The additional formula is as follows:

11

i

e

tTt

−=

−

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

Where these tax rates are equal the factor calculates to the value of one, and the delevering and relevering formulae are as currently provided in Sections 4.9.7 and 4.9.8 of the RTWR.

6.1.6 This Chapter explores the values of the input variables which comprise the WACC using market input variables sourced around June 30, 2009. It also looks at the material difference in WACC values which result from examination of these two suggestions arising from the consultation process. That is, firstly examining the approach recently suggested by the Distribution Utilities to using a regulatory WACC output from taking input values at around the 75% of the range of observed market values. And secondly comparing the regulatory WACC output where the RTWR formulae are used against where the additional factor is incorporated in the formulae as proposed by NGCP based on the analysis derived from Professor van Zijl.

6.1.7 However, it is important to stress that the ERC currently prefers input values central to the range of market values found and the existing formula from the RTWR as a basis for its decisions for the Third Regulatory Period. Adoption of none, one or both of these suggestions cannot be contemplated unless it is part of the NGCP application, and has been subject to the public hearing process associate with such application.


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6.2 Locked Parameters 6.1.8 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 general 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 market place, which is a relatively young and small market without historical market measures from a sufficiently long time period to assist statistical accuracy, and 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 Section 5.9.1 of the RTWR. Thus the Market Risk Premium (MRP) is set to 0.06 (or 6.0% pa).

6.1.9 Previously the gearing ratio was set at 50% funding by Debt and 50% funding by equity, resulting in a Debt / Equity ratio of 1.0 or Debt / (Debt + Equity) and Equity / (Debt + Equity) ratios of 2.0. Submissions by industry participants suggest this level of gearing contains too much debt for an investment in transmission networks in the Philippines. The ERC is of the view that it should initially unlock the gearing ration chosen to allow the debt funding to be explored further, and in particular initially to fall to 15% and make the equity funding 85%. The remaining analysis is undertaken at the higher gearing ration of 15% funding by Debt and 85% funding by equity, but the application by NGCP should explore both the 50% to 50% gearing currently provided in the RTWR and possibilities of debt levels which lower the proposed WACC, which the ERC shall take through the public consultation process leading to its Draft Determination.

6.2 Estimate of Risk Free Rate in the Philippines

6.2.1 The discussion in Section 4.9.5 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 Philippines peso Treasury Bond resulting from the auction process undertaken by government. Secondly the return on a long dated USA treasury bill plus the yield difference between peso and US$ bills available within the Philippines. The following paragraphs explore each outcome.

6.3 Direct Measure of Risk Free Rate in the Philippines 6.3.1 Information on the yield of the 10 year Philippines Treasury Bond

suggests the yield resulting from the auction process for fixed rate Treasury bonds on June 23, 2009 with a nominal yield of 7.875% 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


Page 46

risk-free investment by debt providers in the Philippines. However, given a “normal yield curve” (ie a slowly rising yield curve with a similar shape to Figure 6.1) 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 above this rate.

T-Bill / T-Bond Rates

R2 = 0.9208

-

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

- 2.0 4.0 6.0 8.0 10.0 12.0

Tenor (years)

Inte

rest

Rat

e (%

pa)

Figure 6.1 : Yield curve for Philippine Treasury Bills and Bonds for June 2009

6.4 In-Direct Measure of Risk Free Rate in the Philippines

6.4.1 In order to apply the high-liquidity risk-free rate from the USA in the Philippines, the estimate needs to remove the USA 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 USA. This country risk premium (CRP) can be best measured through the yields offered on US$ bonds in the Philippines and US$ 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 USA. This measure excludes foreign exchange risk. The following paragraphs isolate estimates of this data.


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6.5 Risk Free Rate in the USA 6.5.1 Data was drawn from the Federal Reserve of the USA statistical data Table

U15 of the average yields for July 2009 for 10 year maturity Treasury bonds. The average yield was a nominal yield of 3.576% pa2. The range of values at one standard deviation was between 3.453% pa and 3.699% pa. While the ERC has used this data for this Position Paper, 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.

6.6 CPI in the USA

6.6.1 This nominal yield includes US inflation. Data on the USA inflation rate was also sourced from the US Department of Labor – Bureau of Statistics, for All Items, US Cities average, non-seasonally adjusted. Figure 6.2 shows that the monthly inflation rate using data between January 2002 and June 2009. The inflation rate in the USA has been quite volatile over this period, and in recent months has dropped rapidly as a result of the global financial crisis, becoming negative in the second quarter of 2009.

USA Annual Inflation Rate

-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

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

Figure 6.2 : USA Inflation Rate (% change by month on previous year)

6.6.2 The following Table 6.1 provides the spot, six month average and twelve month average USA inflation rates to the end of June 2009. The dramatic reduction in the last quarter of 2009 is evident.

2 Average last 5 Friday averages to July 17, 2009.


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Period for Average

Average of Monthly Inflation

Rates (% pa)Spot (1.43%)6 m (0.59%)12 m 1.43%

Table 6.1 : Average USA Inflation Rate to End June 2009 (% pa) 6.6.3 Data was drawn from the Federal Reserve of the USA statistical data Table

U15 of the average yields for July 2009 for 10 year maturity inflation-indexed bonds. The average yield was a nominal yield of 1.866% pa3. 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 suggests USA inflation was 0.59% pa around the end of June 2009.

6.7 CPI in the Philippines 6.7.1 Information on the consumer price index (CPI) on the Philippines sourced

from the National Statistics Office of the Philippines (NSO) 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 1.5%pa at the end of June 2009 (refer Figure 6.3 below). The Philippines inflation rate, similar to the data from the USA, appears to be falling in response to the reduction in consumer demand due to the uncertainties resulting from the global financial crisis.

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

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 '04 Spot Dec '08

Spot Jun '09

Figure 6.3 : Philippines Inflation Rate (% pa)

3 Average last 5 Friday averages to July 17, 2009.


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6.7.2 The following Table 6.2 provides the spot, six month average and twelve month average Philippines inflation rates to the end of December 2009. The dramatic reduction in the last quarter of 2009 is evident.

Period for Average

Average of Monthly Inflation

Rates (% pa)Spot 1.52%6 m 5.06%12 m 7.99%

Table 6.2 : Average Philippines Inflation Rate to End June 2009 (% pa)

6.7.3 The difference in response to the CPI measured in the USA and that measured in the Philippines is clearly seen in Figures 6.2 and 6.3 respectively. The drop in the Philippines is lagging slightly the drop seen in the USA. The effect from both changes should be that the regulatory WACC seen for NGCP will drop in nominal terms.

6.8 Philippines Country Risk Premium 6.8.1 The ERC has been accessing the Country Risk Premium data from a

PricewaterhouseCoopers (PwC) source for the period from around 2003 to end of 2007, for development of regulatory WACCs for both NGCP and Distribution Utilities. The data is provided in Figure 6.4.

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%

Figure 6.4 : Philippines CRP (% pa)


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6.8.2 The ERC is hoping to access additional CRP data from this source for the 2009 year for Draft Determination report.

6.9 Philippines Country Risk Premium 6.9.1 An estimate of the risk free rate in the Philippines is thus possible from the

following formula:

rf = (1+rUSA) / (1+CPIUSA) x (1+CPIPhil) x (1+CRP) – 1

Where:

rUSA = 0.0345 to 0.0370;

CPIUSA = 0.0009 to 0.0277 (using +/- one-half of a standard deviation of the twelve month average to June 2009);

CPIPhil = 0.0618 to 0.0981 (using +/- one-half of a standard deviation of the twelve month average to June 2009); 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 offshore measures is between 11.5%pa and 13.4%pa.

6.10 Review Direct and In-Direct Measure of Philippines Risk Free Rate 6.10.1 The measure achieved by an in-direct measure of the risk free rate suggests

a range from 11.5%pa and 13.4%pa. The direct measure suggests a risk free rate of about 7.9%pa. The measures are not consistent within the range of estimates, but are influenced by input measures of inflation (see the outcomes of paragraphs 6.6 and 6.7 above) and the use of a twelve month average for inflation in the in-direct measure. This is being compared to a Philippines bond auction on a single day in the direct measure. The ERC has some concern that the extreme liquidity pumped into the global markets due to the global financial crisis is now beginning to have an impact on the supply and demand level in the Philippines bond auctions (demand exceeding supply), with the effect that auctions yields are falling in the short -term. Given the volatility of the markets due to the global financial crisis which the ERC believes should be a short to mid-term issue, it is inclined to use the average CPI measures to develop estimates of the risk-free rate using an in-direct measure of market data. Thus without committing to a final value for the risk free rate, the ERC in undertaking its analysis for this Position Paper shall use a range of values derived from an in-direct measure which lie between 11.5%pa and 13.4% pa.


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6.11 Measurement of Benchmark Equity Betas 6.11.1 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 and hence the statistics on the equity beta are note particularly accurate. Table 6.3 below suggests a range of the derived asset beta of between 0.36 and 0.96 with a mean of 0.633. This is after application of the formula in Section 4.9.8 of the RTWR.

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

Minus One Standard Deviation -17.80% 67.28% 40.04% 40.04%Plus One Standard Deviation 112.33% 102.08% 85.02% 85.02%

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

Minus One Standard Deviation 17.83% 55.22% 36.47% 44.01%Plus One Standard Deviation 119.54% 106.81% 73.50% 83.29%

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

Table 6.3 : Overseas Transmission Company Equity and Asset Betas


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6.12 De-Levering to Asset Beta 6.12.1 In Table 6.3, the equity betas measured in overseas equity markets are de-

levered using the formula in Section 4.9.8 of the RTWR. The D/E 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 Table 6.3.

6.12.2 During its analysis of regulatory WACC for Distribution Utilities, the ERC noted that its use of the Hamada formula used 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, this distortion is felt to be small. In this instance the corporate T Factor mentioned in paragraph 6.1.5 above is taken to be equal to 1.0.

6.13 Selecting a NGCP Asset Beta 6.13.1 Without committing to a decision on an appropriate asset beta for NGCP,

the apparent range of asset beta to explore the WACC range which might be applicable for NGCP for the Second Regulatory Period is between approximately 0.40 and 0.85 which are the minus and plus one standard deviations of the mean of 0.633.

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

6.13.3 The ERC flags in this Position Paper that following the NGCP submission of Annex F, and previous submissions of material from Professor van Zijl, the issue of which delevering formula should be applied for the estimate of regulatory WACC for the Fourth Regulatory Period, will need to be considered following a public consultation sometime during the Third Regulatory Period. The formula in paragraph 6.14.3 below might be an appropriate starting point for public consultation.

6.14 Re-Levering to NGCP Equity Beta

6.14.1 The formula in Section 4.9.7 of the RTWR is used to re-lever the asset beta to an equity beta for regulatory purposes using the D/E ratio of 15%:85% or 0.18.

Betae = Betaa x [1 + (D/E)]

Thus using this formula the NGCP equity beta is assumed to lie between 0.47 and 1.00, with a mid range value of 0.78.

6.14.2 Where the formula proposed by NGCP (which was derived from analysis by Professor van Zijl using the implied ERC assumptions, as stated in Annex F of the NGCP submission) is used re-lever the asset beta to an equity beta for regulatory purposes using the D/E ratio of 15%:85% or 0.18, the following formula applies.


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Betae = Betaa x [1 + ((1 - tc) / T) x (D/E)]

It should be noted that the corporate income tax rate under RA 9511 is zero, so the formula further simplifies to the following.

Betae = Betaa x [1 + (1 / T) x (D/E)]

Using the personal tax rate on dividends as 10% and the personal tax rate on interest income of 20%, the value of T derived using the formula in paragraph 6.1.5 above is 0.89. Thus the NGCP equity beta is assumed to lie between 0.48 and 1.02, with a mid range value of 0.79. Thus using the NGCP proposed relevering formula we see a 1.9% increase in the equity beta estimate using the methodology proposed by NGCP, at this relatively low gearing ratio.

6.14.3 The Annex F in NGCP’s submission indicates that in its view the ERC’s use of relevering formula is flawed. It indicates that if the ERC believes there is a debt margin (DM) to calculate the cost of debt (see s.4.9.10 of the RTWR), then under finance theory there should also be an debt beta (resulting from debt yield market volatility) which offsets some of the equity beta which would otherwise be derived from the asset beta using one of the formula in paragraph 6.14.2 above. The NGCP submission does not present the relevering formula which includes the debt beta but the ERC’s analysis suggests such a formula might look like the following:

Betae = Betaa x [1 + ((1 - tc) / T) x (D/E)] - Betad x ((1 - tc) / T) x D/E)

or where the corporate tax rate is zero this simplifies to the following:

Betae = Betaa x [1 + (1 / T) x (D/E)] - Betad x (1 / T) x D/E

The ERC notes the value of this more detailed analysis in not inflating the required equity beta to account for the observed asset betas overseas, as some of the volatility is attributable to debt yields and this has become prominent in the current GFC. The outcome of the use of this formula is that the required return to equity will fall slightly, before it is applied in the WACC formula.

6.14.4 The ERC flags in this Position Paper that following the NGCP submission of Annex F, and previous submissions of material from Professor van Zijl, the issue of which relevering formula should be applied for the estimate of regulatory WACC for the Fourth Regulatory Period, will need to be considered following a public consultation sometime during the Third Regulatory Period. The formula in paragraph 6.14.3 above might be an


Page 54

appropriate starting point for public consultation for amendments to the RTWR before the Fourth Regulatory Period.

6.14.5 It should also be noted that in considering to include the T Factor in the relevering formula, NGCP is making the assumption that the personal tax rate on dividends and the personal tax rate on interest income are important (refer to paragraph 6.1.5 above). The ERC is not convinced the personal tax rates apply in assessing the return required for NGCP as an investor, given its is a corporation, and subject to RA9511 rather than the Philippines tax law. This issue will also need further public consultation before being adopted into the RTWR.

6.14.6 The ERC notes that the proposed NGCP asset beta assumed to lie between 0.36 and 0.96, with a mid range value of 0.633 from paragraph 6.14.1 above is substantially lower than the regulatory asset beta used by the Australian Energy Regulator (AER) in its transmission decisions which is set a 1.0. 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 1.0 was reasonable.

6.14.7 In its analysis of the equity betas for Distribution Utilities, the ERC has noted that the use of the simple Hamada formula may be distorting the WACC outcomes as gearing ratio is varied. The end result is that the WACC does not fall appreciably as the gearing ratio is increased. This may mean that more complex re-levering formula are required to better represent the risks which derive from either debt beta or equity beta (such as the formula explored in paragraph 6.14.2 and 6.14.3 above). The ERC views these influences do exist in the analysis, but are likely to be second order terms in the analysis (ie: have lower impact on the outcomes than first order terms such as corporate tax rate).

6.14.8 NGCP in Annex F also make the claim that the exclusion of the asset beta means the WACC will rise as the debt or D/E ratio increases. Indeed the ERC believes the move to the formula in paragraph 6.14.3 above (or its agreed equivalent following public consultation) will likely eliminate this distortion. However, the ERC has further explored the issue of increasing WACC with increasing D/E ratio using a re-levered equity beta formula with the asset beta included (ie: the formula in paragraph 4.14.3 above) and with and without the inclusion of corporate income tax in the analysis. The following Figure 6.5 shows the effect of gearing when the corporate income tax rate is assumed to be 30%.


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Weighted Debt & Equity and WACC vs GearingBottom Cost of Debt

-

2.00%

4.00%

6.00%

8.00%

10.00%

12.00%

14.00%

16.00%

18.00%

- 10% 20% 30% 40% 50% 60% 70% 80% 90%

Debt Ratio

Ret

urn

(%pa

nom

inal

)

Weighted Rd Weighted Re WACC

Figure 6.5 : Complex Re-levering formula with T Factor, Asset Beta & 30% Corporate Income Tax

6.14.9 The ERC notes the WACC falls with increasing D/E ratio. The following Figure 6.6 shows the effect of gearing when the corporate income tax rate is assumed to be 0%, as required by the RA9511.

Weighted Debt & Equity and WACC vs GearingBottom Cost of Debt

-2.00%4.00%

6.00%8.00%

10.00%12.00%14.00%

16.00%18.00%20.00%

- 10% 20% 30% 40% 50% 60% 70% 80% 90%

Debt Ratio

Ret

urn

(%pa

nom

inal

)

Weighted Rd Weighted Re WACC

Figure 6.6 : Complex Re-levering formula with T Factor, Asset Beta & 0% Corporate Income Tax


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6.14.10 The ERC notes the WACC increases with increasing D/E ratio. The ERC believes this first order impact is what NGCP is referring to in its Annex F submission. However, it is not an asset beta issue, rather a corporate income tax issue. The ERC notes this outcome is counter-intuitive given the WACC formula in s.4.9.3 of the RTWR, but can possibly be explained by the following points:

(a) Where corporate income tax is 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, 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, allowing WACC to increase in a counter intuitive manner.

6.14.11 The ERC would seek NGCP’s filing for the regulatory reset to explore this issue, and in particular present results at both a 50% : 50% and 15% : 85% debt to equity ratio, in order for the ERC to confirm its initial analysis in this Position Paper. Justification for different outcomes or for a different approach to the use of the equations specified in the RTWR would need to be provided in this submission, and be subject to public consultation prior to the ERC developing its Draft Determination.

6.14.12 The question which is critical for the ERC in developing a view on the NGCP filing, is where the formula in paragraph 6.14.1 above is used to re-lever the asset beta to an equity beta, what gearing should be used in the post RA9511 environment? If the analysis above is correct and higher gearing requires a higher WACC to be included in the building block analysis, the argument for a regulatory balance between rates charged to consumers and encouragement of investment by the regulated entity suggests lower gearing would be appropriate. This is why the ERC has initially suggested moving away from the 50% : 50% debt to equity ration preferred in the RTWR. The ERC believes the above analysis at a zero corporate income tax rate means that allowing a high D/E ratio in the building block analysis for the regulatory reset would likely not be an economically efficient outcome.

6.14.13 The ERC is of the view there is sufficient flexibility in Section 5.9 of the RTWR to allow the above changes to the D/E ratio in the calculation of the WACC formula for the Third Regulatory Period. Notwithstanding the ability to change the formula in Section 4.9.7 of the RTWR in the current process to review to something like the formula in paragraph 6.14.3 above and amend the RTWR, this specific change will not be contemplated until further public consultation occurs during Third Regulatory Period. The following analysis continues with the use of a 15% : 85% D/E ratio.


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6.15 Estimated Range of Return to Equity 6.15.1 Using the formula in 4.9.4 of the RTWR and the data ranges above, the

range of return to equity to be used for regulatory purposes lies between values shown in Table 6.4 below, depending on the equity beta formula used. These are an estimate of the range of the return equity investors would expect to receive for investing in an electricity transmission business in the Philippines.

Formula for Equity Beta Low Range Mid Range High Range

As s.4.9.7 of RTWR 14.28% 17.09% 19.36%

As Annex F NGCP Sub 14.34% 17.18% 19.48%

As para. 6.14.3 formula based on extension of Prof. van Zijl analysis 14.24% 16.97% 19.14%

Note : All values are nominal %pa.

Table 6.4 : Regulatory WACC Summary

6.16 Estimated Range of Debt Margin

6.16.1 At present the ERC does not have a lot of data on the debt margin above the risk free rate that debt provider would expect for provision of debt to an electricity transmission business in the Philippines. For this Position Paper the ERC makes the assumption that a large private company in the Philippines with a similar risk profile 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 most recent work on the Distribution Utilities. The ERC recognizes that a pure transmission company should have better access to debt funds than a Distribution Utility which is a combined wires and retail electricity business (and sometimes included 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 Distribution Utility.

6.16.2 The ERC will explore the value of the debt margin to use for NGCP to develop a regulatory WACC for the Draft Determination.

6.17 Estimated Range of Return to Debt

6.17.1 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 13.7%pa and 16.1%pa (nominal) (see Section 4.9.10 of the RTWR).

6.18 Estimated Range of WACC 6.18.1 Using the above data and the formula in Section 4.9.3 of the RTWR, the

estimate of the WACC to be used for regulatory purposes as at end January, 2009 would lie within the range of 14.2%pa and 18.9%pa, post-


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tax nominal basis, or the same at between 14.2% and 18.9% on a vanilla WACC basis. The reason it is the same is because the corporate income tax rate is now zero. The mid-point WACC value calculation using the RTWR formula is summarized in Figure 6.7 below.

Market Risk Premium

6.0%Company Equity Risk Premium

4.7%Cost Levered Company Beta (1)

0.78of Cost of Equity 85% (5)

17.1%Equity

Risk Free Rate (2)12.4%

WACC WACC16.77% 16.77%

Risk Free Rate (2) (post-tax nominal) (vanilla)12.4%

Levered Company Cost of Debt14.9%

Cost Levered Debt Premium (3)2.50%

of Net Cost of Debt14.9% 15% (5)

DebtMarginal Tax Rate (4)

0.0%

Figure 6.7 : Summary of Regulatory WACC Estimate

(%pa post-tax nominal and nominal vanilla)

6.18.2 Table 6.5 below provides the summary of the range and mid-point calculation for the regulatory WACC for the Position Paper using the formula in the RTWR and the adjusted formula proposed by NGCP as developed by Professor van Zijl.


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NGCP Regulated WACC Estimate for Position Paper - Base on Peso Debt FinancingWACC Calculation WorksheetInput only in shaded cells

Paramaters Low Mid High

Gearing (Debt) ratio D/(D+E) 15% 15% 15%Equity ratio E/(D+E) 85% 85% 85%Debt to Equity D/E 0.18 0.18 0.18Asset beta (degeared empirical beta) ßa 0.400 0.663 0.850Debt beta ßd 0.080 0.180 0.280

Risk free rate (nominal - US$ 10 Year Bond Yields in USA) 3.45% 3.58% 3.70%Country Risk Margin (excluding FX Risk) CRP 1.56% 1.94% 2.32%Risk free rate used in WACC Rf 11.46% 12.41% 13.36%

Debt Margin DM 2.25% 2.50% 2.75%Cost of debt (pre-tax nominal peso terms) Kd 13.71% 14.91% 16.11%Market Risk Premium (Developed Country) Rm - Rf 6.00% 6.00% 6.00%Corporate tax rate tc - - -

Inflation rate (Philippines) i 6.18% 7.99% 9.81%Inflation Rate (USA) 0.09% 1.43% 2.77%Income Tax Rate on Interest Income 0.20 0.20 0.20Income Tax Rate on Dividend Income 0.10 0.10 0.10T Factor, where T = (1-ti)/(1-te) T 0.89 0.89 0.89Calculated Equity (Regeared) Betas Formula Low Mid HighEquity Beta (1) Simple No Tax Adjustment - RTWR 1 0.47 0.78 1.00Equity Beta (2) Simple Tax Adjustment 2 0.47 0.78 1.00Equity Beta (3) Simple No Tax Adjustment & T Factor - Annex F NGCP 3 0.48 0.79 1.02Equity Beta (4) Complex No Tax Adjustment & T Factor - ERC & Prof. van 4 0.46 0.76 0.96

Other ParametersEquity beta (geared beta) ße 0.47 0.78 1.00Cost of Equity (post-tax nominal) Ke 14.28% 17.09% 19.36%Equity beta (geared beta) using Annex F NGCP ße 0.48 0.79 1.02Cost of Equity (post-tax nominal) using Prof van Zijl Ke 14.34% 17.18% 19.48%Equity beta (geared beta) using ERC extension of Prof van Zijl ße 0.46 0.76 0.96Cost of Equity (post-tax nominal) using Prof van Zijl Ke 14.24% 16.97% 19.14%

WACC Matrix - Commercial Practice & RTWRPost-tax nominal 14.20% 16.77% 18.88%Post-tax real 7.55% 8.12% 8.26%Pre-tax nominal 14.20% 16.77% 18.88%Pre-tax real 7.55% 8.12% 8.26%

Vanilla WACC (nominal) 14.20% 16.77% 18.88%

WACC Matrix - Annex F NGCP SubmissionPost-tax nominal 14.24% 16.84% 18.97%Post-tax real 7.59% 8.19% 8.35%Pre-tax nominal 14.24% 16.84% 18.97%Pre-tax real 7.59% 8.19% 8.35%


WACC Matrix - ERC extension of Prof van Zijl Cost of EquityPost-tax nominal 14.16% 16.66% 18.69%Post-tax real 7.52% 8.02% 8.09%Pre-tax nominal 14.16% 16.66% 18.69%Pre-tax real 7.52% 8.02% 8.09%


Regulatory WACC Estimate by ERC

Table 6.4 : Regulatory WACC Summary


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6.19 Comments on Data Sources and WACC Estimate 6.19.1 As required by Section 4.9.11 of the RTWR the ERC shall seek further

comment on the data sources and the methods of data development to arrive at an estimate of the regulatory WACC for the Draft Determination.

6.20 Recalculation Point Using Market Data 6.20.1 In a performance based regulatory (PBR) analysis, the regulator must

undertake a forward looking projection of the Regulated Entity’s cash flow requirements to assist in setting the revenue cap for the coming regulatory period. It is not in the regulator’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.

6.20.2 Thus the regulator measures a WACC at one 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.

6.20.3 The ERC notes that the CWI factor in the revenue cap formula, which is based on CPI or a combined CPI and Exchange Rate index, then corrects the revenue stream for changes in costs experienced by the Regulated Entity, including the market changes in the WACC, because in the normal course of market outcomes, there is positive correlation between the CPI and the WACC, although this is not strictly a direct correlation.

6.20.4 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, and now as at June 30, 2009 in the Position Paper. The majority of the input data for the WACC is sourced from around each of these dates.

6.20.5 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 March 2010. This date allows some time for the ERC to complete the calculations and publish its Draft Determination of the revenue cap for NGCP, which is scheduled to occur by April 30, 2010.


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7

CHAPTER 7

PERFORMANCE BASED REGULATION

7.1 Performance Indices for Third Regulatory Period 7.1.1 In the Final Determination for the Second Regulatory Period, the ERC

decided to adopt five performance indicators for the Performance Incentive Scheme (PIS). The five Performance Indicators (PI) adopted for the Second Regulatory Period are:

(a) System Interruption Severity Index (SISI);

(b) Frequency of Tripping per 100ckt-km (FOT/100ckt-km);

(c) System Availability (SA);

(d) Frequency Limit Compliance (FLC); and

(e) Voltage Limit Compliance (VLC).

7.1.2 The ERC believes these same five PI should be applied for the Third Regulatory Period as a minimum. During the regulatory reset process for the Third Regulatory Period the ERC requires NGCP to deliver additional performance data on the PIs above and on other additional measures of network performance. In particular the ERC will require information on the additional PIs described in the Grid Code, and those provided in Appendix A of the RTWR. Where the information exists, NGCP is requested to provide data on all of the PIs described in the Grid Code and Appendix A of the RTWR.

7.1.3 While NGCP has measured the performance information for each of the Luzon, Visayas and Mindanao grids separately, under Appendix B of the RTWR, NGCP was not able to provide information on the performance of the ‘sub-sea or inter-island’ interconnectors during the regulatory reset for the Second Regulatory Period. The ERC would like a report of whether this information is now available for consideration during the regulatory reset for the Third Regulatory Period.

7.1.4 In the Paragraph 8.8.2 of Final Determination for the Second Regulatory Period, the ERC requested the Grid Management Committee (GMC) to develop potential PI on transmission congestion. The GMC has provided its report to the ERC on congestion measures. The outcome is that reliable measures outside those available from the WESM are difficult to identify and may not be useful for inclusion of a PI. Nonetheless the ERC will consider the GMC report further and believes that concern from industry stakeholders over network congestion requires further exploration of incentives to encourage NGCP to invest to remove congestion.


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7.1.5 The ERC notes the submission from Meralco which has suggested the following four measures which may help monitoring congestion issues:

(a) Availability of transmission lines;

(b) Availability of power transformers;

(c) Duration of transmission outages; and

(d) Compliance to capital expenditure program schedule.

7.1.6 Meralco has also suggested a PI which measures the economic impact of congestion, but does not fully explain how this might be achieved. It has made the comment that “[o]ne measure that can be used to gauge the cost of congestion is to estimate the difference between the market constrained cost (i.e., the resulting overall market cost when transmission congestion exists) and the unconstrained cost (i.e., the overall market cost when transmission congestion is removed or non-existent)”. The ERC notes this would require the input from the Market Operator to provide this measure, and it is not clear whether the current market modeling arrangements can measure this already or whether modification or external analysis would be required to obtain a measure of such a PI. The ERC believes that any measure from the WESM market model would not provide discrete measures of the economic impact of a particular congestion, but would integrate the effects of congestion across all times and days of operation. As such it may dilute the impact of such a measure for use as a PI as the measure will by its approach, tend to “average” the effects over time. Nonetheless, this measure should be looked at in more detail as NGCP prepares for its application and the ERC moves towards its Draft Determination. In order to better understand whether the WESM market model can provide such a PI, the ERC requests the Market Operator to prepare a draft report on the possible measures which could be used based on the current implementation of the market software, eg: shadow prices, financial transmission rights or other. The ERC requests the Market Operator to undertake a consultation process with the GMC, and from this process prepare a final report on the possible approaches, their advantages and disadvantages, and with examples of the output which can be generated, by December 31, 2009. This information will be used by the ERC in developing its Draft Determination in relation to a PI which could be used to monitor and incentivize the reduction of congestion in the transmission network.

7.1.7 The ERC also notes that Meralco has made other suggestions over how the System Operator and NGCP may work towards improved performance from the transmission network. The following comments were received from Meralco.


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“We respectfully recommend a number of ways by which the Transmission Provider can address transmission congestion, some of which are listed below:

(a) Reinforcement of the critically loaded segment of the transmission system;

(b) System operations practices which takes into account not only availability and reliability, but also the economic implications of operating decision;

(c) Planning of maintenance outages at locations and times when it is highly unlikely that it will result to transmission congestion;

(d) Reducing outages by adopting different maintenance procedures (e.g., live-line work);

(e) Coordinating network outages so as to maximize maintenance work within the outage duration;

(f) Reducing the duration of outages through better work planning or better use of equipment;

(g) Ensuring that transmission components are available when they are needed in the competitive market; and,

(h) Advance notification of market participants so that they can mitigate the impact of the outage through other means (e.g., contracting).

The Transmission Provider should ensure that it has considered in its planning for its system development and maintenance, and operation of the system adequate criteria to consider the trade-off between reliability and cost.”

The ERC notes that a number of amendments to the OATS Rules which are currently before the ERC for approval, introduce a number of these approaches and the ERC believes once the amended OATS Rules are implemented by NGCP, there will be the potential for continuing incremental improvement in transmission network performance.

7.1.8 The ERC believes some of these suggestions have merit as objective performance measures which could form part of the PIS under Section 8.2 of the RTWR, and in particular comments on additional suggestions for a congestion PI shall be considered during the regulatory reset process. The ERC looks forward to additional suggestions from NGCP in its application, and in addition requires that NGCP provide the data for the existing PI over the Second Regulatory Period up to the end of September 2009 in its application, so that all industry stakeholders may make further comments on the implementation of the existing and possibly new PI during the Third Regulatory Period.


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7.1.9 The ERC is currently reviewing changes to the Open Access Transmission Service (OATS) Rules in relation to the reporting of reliability issues relating to unplanned outages. The issue of industry participants not being able to find out information on the position, severity and likely duration of unplanned outages has been raised in the public consultation on the OATS Rules. The clauses C3.2 and C8.2 have been suggested to be amended to mandate the reporting and timely publication of such information. To assist the implementation of these clauses the ERC initially proposes to introduce a customer service PI in the PIS. This would be a Fault Reporting measure of customer service being the percentage of time NGCP publish the report on its web site for unplanned maintenance or forced outage within 12 hours of its occurrence (or another period as approved by the ERC following public consultation), as required under clause 8.2(b) and clause 3.2 of the OATS Rules.

7.2 Determination of Performance Targets 7.2.1 Clause 10.4.2 of the Grid Code indicates that the “initial targets shall be

set to the mean value of the particular Grid’s reliability performance for the last five (5) year. The upper and lower cut-off points shall be set at plus or minus one (±1) standard deviation from the mean value.”

7.2.2 Table 7.1 below shows the Bandwidth for the Performance Incentive Scheme / Reward and Penalty Mechanism of the Performance Indices in each Grid determined by the ERC for the Second Regulatory Period.

PI Collar (Penalty)

Deadband Cap (Reward)

Max. Measure Low Target High

-3% 0% 0% 0% 3% Luzon

SISI 26.63 21.86 17.08 12.31 7.53 0 min. FOT 11.23 9.56 7.88 6.21 4.53 0 min. SA 98.94 99.06 99.19 99.32 99.44 100%

FLC 99.85 99.90 99.95 100.00 No reward 100% VLC 59.13 70.10 81.06 92.02 100(<3% max. reward) 100%

Visayas SISI 647.41 460.10 272.80 85.50 0(<3% max. reward) 0 min. FOT 11.29 9.14 7.00 4.86 2.72 0 min. SA 98.75 98.90 99.05 99.20 99.35 100%

FLC 96.24 97.49 98.73 99.98 100(<3% max. reward) 100% VLC 97.52 98.53 99.55 100 No reward 100%

Mindanao SISI 135.16 98.37 61.59 24.81 0(<3% max. reward) 0 min. FOT 16.43 12.99 9.55 6.12 2.68 0 min. SA 98.24 98.66 99.08 99.50 99.91 100%

FLC 99.63 99.74 99.84 99.94 100 (<3% max. reward) 100% VLC 96.44 97.43 98.42 99.41 100 (<3% max. reward) 100%


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Table 7.1 : Bandwidth for the PIS for the Second Regulatory Period

7.2.3 The ERC did not receive any substantive comments on the detail of how these values for the PIS parameters should change for the Third Regulatory Period. Also there may be situations where certain escape clauses are necessary to avoid undue impact on additional investment or excessive reward. The ERC did not receive any substantive suggestions on such mechanisms which would be useful from submissions on the Issues Paper. As such the ERC shall further consult on the detail of the PIS leading up to the development of its Draft Determination.

7.3 Determination of Reward / Penalty Targets 7.3.1 The ERC adopted the following weightings to use in the reward / penalty

PIS for the five PIs, based on the regulatory reset process leading to its Final Determination for the Second Regulatory Period with an objective of encouraging improvements in those grids that were not performing well with respect to each PI: Summary of which is shown in Table 6.2 below.

PI Weightings Weightings by Grid Luzon Visayas Mindanao Total

SISI 45% 20% 50% 30% 100% FOT 25% 32% 29% 39% 100% SA 10% 34% 33% 33% 100% FLC 10% 34% 33% 33% 100% VLC 10% 29% 36% 35% 100% Total 100%

Table 6.2 : PIS Weightings by PI and Grid

7.3.2 The weightings by PI were based on encouraging better performance from those measures which were considered to be most highly valued by customers. Also recognizing that PI with a smaller standard deviation can over-reward or over-penalize NGCP for small movements in the measured PI, lower weightings were proposed to be assigned to SA, FLC and VLC which all have a small (or narrow) deadband. In addition, ERC felt that the SISI was more important as a measure of customer focus than FOT, as SISI represents long-duration unserved energy, the loss of which can adversely affect customers.

7.3.3 The penalty / reward weightings by grid were based on NGCP’s proportional average performance from 2000 to 2004 (bad performance in all measures gives a higher proportion of the average PI compared to the grid with better performance). As an example using the 2000 to 2004 PI data, for SISI, the proportional average performance would provide the following weights:


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Grid Weighted Percentage Luzon 5%

Visayas 77% Mindanao 18%.

Table 6.3 : SISI Weightings by Grid

7.3.4 The overall weightings applied to each PI within each grid to derive the PIS outcomes, are the multiple of the PI weighting and the grid weighting.

7.3.5 All of the weightings and triggers will need to be updated for the Third Regulatory Period based upon NGCP’s performance during the Second Regulatory Period up to the end of September 2009, once this information is provided by NGCP.

7.3.6 The ERC is proposing to have the weighting for the new proposed customer service measure of Fault Reporting set at a high level of 30% because of the importance industry participants have indicated on the prior lack of performance by TransCo on the issue of timely reporting of unplanned outages in the transmission system. This level will be determined by the ERC following public consultation during the regulatory reset process for the Third Regulatory Period.

7.3.7 While these performance targets are set for the PIS, other targets for PI may be developed from comments such as have been summarized in paragraphs 7.1 above. The ERC encourages stakeholders to provide further comment on the reward / penalty arrangements which could be used for PBR purposes in the Third Regulatory Period. Also there may be situations where certain escape clauses are necessary to avoid undue impact on additional investment or excessive reward. Suggestions on such mechanisms would be useful in the discussion of the approaches which the ERC might eventually adopt, and should be the focus of submissions during the regulatory reset process which kicks off once NGCP provides its application to the ERC.

7.4 New Congestion Performance Measures 7.4.1 In it submission of August 2009, Meralco proposed two measures relating

to the number and severity of transmission congestion which the ERC believes should be further explored as potential performance measures which might be included in the PIS. These proposed measures are:

(a) Frequency of Congestion; and

(b) Congestion Severity Cost.

7.4.2 Meralco suggests these measures can be developed from data which already exists in the formulations or algorithm embodied in the Market


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Dispatch Optimization Model (MDOM) which has been approved by ERC with the approval of the Price Determination Methodology.

7.4.3 The Congestion Severity Cost as defined by Meralco is based on the ERC Decision (Case No. 2008-51 dated February 16, 2009), where Philippine Electricity Market Corporation (PEMC) proposed a settlement “mechanism by which transactions in the WESM will be priced and settled during intervals where the pricing results are affected by congestion”. Meralco suggests the difference of the Constrained Cost and the Unconstrained Cost can be taken as a good economic measure of the impact of transmission congestion. This measure would in fact indicate the severity of transmission congestion. The resulting Congestion Severity Cost can be taken as a cumulative measure over a period, both monthly and annually. The formula proposed is as follows:

Congestion Severity Cost (CVC) = Constrained Cost (CC) - Unconstrained Cost (UCC)

where:

CC = Market Constrained Cost be made equivalent to the Constrained Solution as determined by the Market Operator (MO) during the trading intervals where there are congestion-related pricing errors which results to the actual market clearing price (without the application of the Price Substitution Methodology as approved by ERC). The constrained solution refers to the results of the MDOM taking into account the constraints p e r t a i n i n g t o t h e i d e n t i f i e d n e t w o r k c o n g e s t i o n .

UCC = Market Unconstrained Cost be made equivalent to the Unconstrained Solution as defined in the aforesaid Decision. The market clearing price corresponding to the unconstrained solution shall be determined by the Market Operator for trading intervals where there are congestion-related pricing errors. “The unconstrained solution is derived by merit order stacking of the available generators based on their bids and offers for the relevant trading interval and taking into consideration the generator outages, security limits and the demand and losses accounted for in the original (i.e., unconstrained) run”. Theoretically, this is the cost that market participants have to pay when there is no transmission congestion.

7.4.4 The Frequency of Congestion as defined by Meralco is based on the number of “occurrences of CVCs or extreme nodal price separations” which triggers the application of PSM. The occurrences of extreme nodal price separations maybe measured by the trigger factor defined in the ERC Decision. The formula proposed by Meralco is as follows:


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Frequency of Congestion (FC) = Number of Occurrences of CVCs or extreme nodal price separations in a given period

7.4.5 Meralco makes the further observation that “these definitions of the proposed congestion measures ensures transparency of the process considering that all the values can be derived from the information determined and published by the Market Operator. It would not require any modification in the current modeling arrangements, nor require external analysis since the measures can be derived from the resulting values derived by the Market Operator in computing for the PSM in accordance with the ERC Decision. Both the Congestion Severity Cost and the Frequency of Congestion measures can also be used as effective criteria in determining the transmission expansion and reinforcement projects of the Transmission Network Provider when it prepares its annual Transmission Development Plan”.

7.4.6 In order for the ERC to understand these measures of congestion, PEMC as the MO is to prepare statistics and a summary report on a monthly basis for these two congestion performance measures for the period from the commencement of the Luzon market to June 30, 2009. The report should be delivered to the ERC, the NGCP and other industry stakeholders with interest in the regulatory reset of NGCP by December 1, 2009. NGCO is to prepare a supplementary submission on this specific issue by January 31, 2010, having time to digest and consider the information developed by the MO, and including comments upon potential target levels, deadbands around the target, reward/penalty weightings and position within the PIS. The ERC will then include its thoughts on these proposed performance measures and its possible inclusion in the PIS, including on target levels, deadbands, and reward/penalty weightings, in its Draft Determination to be published in mid 2010.


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8

CHAPTER 8

ANNUAL VERIFICATION AND ADJUSTMENT OF TARIFF RATES

8.1 Background 8.1.1 Article VI of the RTWR provides for a revenue cap validation and a tariff

rate adjustment to the revenue cap, for the coming year of the regulatory period. The ERC currently refers to this process as a tariff translation process.

8.1.2 The tariff translation process is tied to the implementation of the OATS Rules and a number of decisions in the regulatory reset process for the Third Regulatory Period will impact on the way the OATS Rules and the tariff translation process occur. The following primary points provide feedback on the submissions received on the Issues Paper, and in some circumstances indicate where further consultation following NGCP’s application will be helpful in development of the tariff translation process.

8.2 Issue 1 – Customer Segmentation 8.2.1 TransCo was asked to undertake a study of alternative customer segments

than those used for the Second Regulatory Period. There have been effectively three (3) customer segments for the Second Regulatory Period, notably, Luzon, Visayas and Mindanao, as defined in the ERC Order dated August 2, 2006 under ERC Case No. 2005-041RC. TransCo’s compliance and the Annex A report attached to this compliance were filed with the ERC on June 2, 2008.

8.2.2 The TransCo report looked at customer segmentation using voltage levels and demand characteristics as the dimensions of each segment, but saw little advantage in the various alternative customer segments examined. Ultimately, TransCo did not provide a specific recommendation to the ERC to replace the customer segments currently utilized. Nonetheless the report had detailed descriptions of possible alternatives.

8.2.3 During the public consultation process on the Issues Paper the ERC requested NGCP to look at the issue separately and to provide a submission on its thoughts as the concessionaire for the TransCo transmission assets. Annex E of NGCP’s submission dated April 2, 2009, provides further consideration of the issue of customer segmentation in the pricing of Regulated Transmission Services. This analysis is extremely helpful in disclosing the issues which the ERC must address as it moves towards the Third Regulatory Period, because it explores broad changes in price experienced by different groups of customers, and the effects that any side constraints imposed by the ERC might have. NGCP concludes that:


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“Though further segmentation of the existing customer segments rationalizes the allocation of the MAR to sub-customer segments, it is still recommended to adopt the existing customer segmentation in order to contemplate the significant increase (price shocks) in the transmission wheeling rates of some transmission customers.”

In particular one of NGCP’s observations is the following:

“Some transmission customers may resist on (changes to the customer segmentation) due to a significant impact of the options on their financial stability. Most of these customers are the one connected at the lower voltages and who pay the largest amount of Connection and Residual Sub-transmission Charges (CC/RSTC).”

This is an extremely valuable observation, as it highlights the differences in approach to pricing by customer segmentation between the Philippines and other jurisdictions. In the Philippines, the move to have Connection and Residual Sub-transmission assets recovered more directly by the customers using these assets has already moved a significant way towards unwinding cross subsidies between customer segments. It suggests further movement towards more detailed customer segments may not be needed in the short term, and potentially not before open access commences in each primary Grid.

8.2.4 The ERC is of the view it should retain the current customer segments for the initial period of the Third Regulatory Period.

8.2.5 However, the ERC is also of the view it will need to move forward from this customer segmentation sometime during the Third Regulatory Period based on an industry specific trigger. Two such triggers which come to mind are:

(a) Firstly the point at which NGCP has fully caught up with the over / under recovery of the revenue cap which the ERC allows to be passed through into the Third Regulatory Period, from which point further tariff rebalancing between customer segments might be possible; or

(b) Secondly, at the point of the initial introduction of retail contestability into each Grid; or

(c) A combination of the two triggers.

From the year after that point there should possibly be a move to a different customer segmentation based on recovery of the costs of the transmission network assets in a manner which does not overly burden any particular customer segment or adversely impact the introduction of retail contestability in each Grid.

8.2.6 In this sense the ERC believes there needs to be more discussion and analysis of the options explored by both TransCo and now NGCP, and


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new options which have not yet been explored in either customer segmentation report. The ERC would seek a further submission from NGCP on this issue in its application filing for the revenue cap for the Third Regulatory Period.

8.2.7 The ERC will seek further consultation on the definition of customer segments under the RTWR (and its impact on the application of the OATS Rules) and what might be used as a trigger for this change, or whether one of the other options explored by NGCP would be more appropriate.

8.3 Issue 2 – Revenue Recovery by Segment 8.3.1 This issue is directly related to the choice of customer segmentation. If the

customer segments are not chosen using a geographical measure such as the Grid, the following approaches could be used to recover the revenue cap on a different customer segment approach. The NGCP Annex E of its April 2, 2009 submission firstly segments by Grid (or Sub-Grid) and then segments by the other parameters, such as voltage level, time-of-use and demand. Where this does not change the ERC must decide how much revenue recovery should come from each customer segment. Decisions on these issues will impact on the OATS Rules which must harmonize with the RTWR. However, it could be equally valid to group all of the transmission network assets for different voltage levels together across the whole of the Philippines, and move away from the “per Grid” initial allocation.

8.3.2 Revenue recovery between customer segments could be in proportion to one or more of the following:

(a) Written-down asset value;

(b) Peak non-coincident load (MW);

(c) Peak coincident load (MW);

(d) Energy consumption (MWh);

(e) Averages of the above by connection, region or grid;

(f) Nodal price by connection; or

(g) Other allocators

8.3.3 The ERC does not believe enough consultation and discussion has occurred on the economic efficiency and investment signals which arise from different customer segmentation and different revenue recovery allocations. The ERC seeks further comment on the type(s) of revenue recovery allocation it could authorize to recover PDS Charges between customer segments, following the filing of the application by NGCP for the Third Regulatory Period.


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8.4 Issue 3 – Connection Services 8.4.1 NGCP has implemented the Connection Service Charge. The approach

enshrined in the OATS Rules is a cost based approach similar to the building block analysis for the main transmission network elements under the RTWR.

8.4.2 The ERC did not receive any comments from industry stakeholders or transmission customers on whether the current arrangements are working or how they might be improved. A further opportunity to provide such comment is possible following the filing of the application by NGCP for the Third Regulatory Period.

8.5 Issue 4 – Side Constraints

8.5.1 During the Second Regulatory Period NGCP has had difficulty in fully collecting its revenue cap, because its revenues have potentially been constrained by the side constraints, rather than the revenue cap.

8.5.2 The NGCP submission on customer segmentation (the Annex E report) provides some insight to the nature of the working of the side constraints comments as they are defined in Section 6.4 of the RTWR . Specific submissions on what per cent factors should be used by the ERC for the side constraints for the Third Regulatory Period were not received from the consultation on the Issues Paper.

8.5.3 The ERC continues to be interested in whether the constraint of 2% pa it has imposed in Section 6.4.1 of the RTWR needs to be amended for the Third Regulatory Period. This constraint could be:

(a) Constant over the whole regulatory period;

(b) A different but fixed value for each year of the regulatory period; or

(c) Defined by a secondary parameter which has an objective measure which could be applied each year of the Third Regulatory Period.

8.5.4 The ERC requires further submissions from NGCP on this issue in its application for regulatory reset and will seek further comment on the side constraints to be used for the Third Regulatory Period from industry stakeholders following the filing of the application by NGCP for the Third Regulatory Period. Initially the ERC proposes to maintain the side constraint at 2% pa but NGCP may propose a relaxation of the side constraint in its application and justify this position in the public hearing process. Ultimately the ERC shall determine the appropriate relaxation of the side constraints should this be warranted following due process in the Regulatory Reset for the Third Regulatory Period.


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8.6 Issue 6 – MAR Allocation between Generators and Loads 8.6.1 In its Customer Segmentation report filed on June 2, 2008, TransCo

manifested its position on the allocation of revenue recovery for the Power Delivery Service (PDS) Charge under the OATS Rules. Specifically TransCo manifested that it was no longer keen on pursuing the proposal to split the recovery of revenues between generators and loads.

8.6.2 For the Second Regulatory Period the ERC did not allow recovery of NGCP revenues from connected generators, but did not close off the issue for future Regulatory Periods. The ERC notes the following issues which need to be discussed and resolved for NGCP to charge generators as well as loads, should it be interested in pursuing this option independently from TransCo:

(a) The investment cycle for mid-range and base-load generators assumes a long plant life, (say) of between 20 to 35 years. Once the investment is committed, there is little opportunity to re-site the generator in an economically efficient manner, particularly for coal-fired generators. Thus locational pricing signals, if any, need to be certain and consistent over long periods, and can be small, in order to have a large impact on the economics of the investment decision.

(b) It is unclear to the ERC whether the current legal and regulatory framework will allow generators to recover all of the charges imposed upon them. Ultimately, the consumers of electricity must fully support the efficient costs of the electricity industry, including transmission costs, in order for a viable industry to develop. A direct charge to loads may be more efficient from an industry administration and efficiency point of view, than a partial recovery from generators.

(c) Once the WESM is in operation, it is unclear whether generators would be able to fully recover a PDS Charge imposed by NGCP. This may lead to non-financial viability for some existing generators which may not be appropriate.

(d) A charge for PDS to existing generators, whose investment is sunk, does not appear to lead to improved economic efficiency.

(e) It is unclear whether existing generator contracts with the supply arms of distribution utilities or with end users will support some form of pass through of a PDS charge on generators.

(f) A charge for PDS for new generators which have yet to site their plant would appear to have a positive impact on economic efficiency, provided the charges lead to reduction in transmission constraints in the short-to-mid term. It should be noted that NGCP’s attitude to removal of existing or identified transmission


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constraints through appropriate transmission investment has probably a stronger and more immediate impact on network efficiency than through positioning a generator on the high demand side of a constraint. However, the decision over whether a transmission investment or a generation investment is more economically efficient in the long-run should be made to determine the best approach for the Philippines electricity network.

(g) Where there is a specific regulatory framework to allow pass through of PDS from generators to suppliers and/or end users, then the benefits of a locational PDS charge to generators appears to be reduced, albeit the methodology used by generators (or the specific regulatory framework) may lead to more economically efficient recovery from a different group of suppliers and/or end users.

(h) It is possible that allocations other than 50% PDS charge recovery from generators might be workable.

8.6.3 The ERC did not receive any comments from industry stakeholders or transmission customers on whether the current arrangements of charging load customers for recovery of 100% of the revenue cap should be changed to have some proportion also recovered from generation customers. On the basis that no substantive comments have been received to the Issues Paper and that the issues discussed in paragraph 8.6.2 have not been adequately addressed, the ERC shall retain the revenue cap recovery ratios as specified by the OATS Rules at 100% for load customers and 0% for generation customers for the Third Regulatory Period.

8.7 Other Issues for Consideration 8.7.1 In this Position Paper the ERC has set out its position on a number of

issues relating to the regulatory reset for the Third Regulatory Period which will allow NGCP to develop its application with more certainty. Where an issue has yet to be exposed sufficiently for public comment the ERC has allowed both NGCP to develop its preferred position for the application and will expect substantive justification for each position preferred by NGCP. The jurisdictional, expository and evidentiary hearings leading to the ERC’s Draft Determination and the following expository, and evidentiary hearings will allow industry participants or the public substantial opportunities to provide feedback and submissions to the ERC on the remaining outstanding issues relating to the regulatory reset for the Third Regulatory Period.


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Pasig City, Philippines, [ ], [ ]

ZENAIDA G. CRUZ - DUCUT Chairperson

RAUF A. TAN Commissioner

ALEJANDRO Z. BARIN Commissioner

MARIA TERESA A.R. CASTAÑEDA Commissioner

JOSE C. REYES Commissioner


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APPENDIX A

ASSET BASE DATA TEMPLATES For the purposes of 4.6.5 of the RTWR the following template should be utilized to provide the summary of the opening re-valued regulatory asset base as at December 31, 2009. The worksheets which feed this template need to show the individual projects and the grouped asset values, the categorization of project types, the justification by project, and the estimation process to get from the US$ and Peso costs through to the total Peso costs, as required by Figure 3.1, in paragraph 3.1 above.

Asset CategoryHistoric Cost

Accumul-ated Historic Cost Depreciation

Depreciat-ed Historic Cost

Weighted Average Age of Asset Category

Weighted Average Asset Life for Tax Purposes

Indexed Cost

Optimized Indexed Cost

Accumul-ated Optimised Indexed Cost Depreciat-ion

Depreciat-ed Optimized Indexed Cost

Weighted Average Age of Asset Category

Weighted Average Asset Life for Regulatory Purposes

(a) Transmission Linesi Buildings, civil works and establishmentii Towers and associated linesiii Poles and associated linesiv Underground cablesv Submarine cables including CTS & CS, ellectrode lines & acessoriesvi Easements owned by the Regulated Entityvii Otherviii Spares, spare parts & toolsix Land owned but used for transmission lines

Sub-total Transmission Lines (b) Transmission Substation Components

i Buildings, civil works and establishmentii Power Transformersiii Circuit breakers & accessoriesiv Instrument Transformersv Protection and control equipmentvi Power compensating equipment, eg: reactorsvii Buswork, power and control cablesviii Otherix Spares, spare parts & toolsx Land owned but used for substations

Sub-total Substation Components(c ) Communication Plant

i Buildings, civil works and establishmentii Communications plant and infrastructureiii Fibre optic cablesiv fibre optic cable terminal equipmentv Ancilliary infrastructurevi Othervii Spares, spare parts & toolsviii Land owned and used for communications plant

Sub-total Communications Plant(d) System Operations

i Buildings, civil works and establishmentii Control room and control infrastructureiii Ancilliary infrastructureiv Otherv Spares, spare parts & toolsvi Land owned but used for systems operations

Sub-total Systems Operations(e) Metering Equipment Assets

i Market metersii Meters which are not Market meters, Connection assets or Subtransmission assets

Sub-total Metering Equipment Assets(f) Non-Network Assets

i Computers and office equipmentii Plant, tools and equipmentiii Furnature and fittingsiv Commercial buildingsv Land owned but used for non-network assets covers all land value not previously attributedvi Other

Sub-total Non-Network Assets(g) Found Assets

i Assets found between a Regulatory Period and the Subsequent Regulatory Period (*1)Allocated Overheads CapitalizedTotal Capital Expenditure

Note (*1) : But not related to capital expenditure, and submitted to the ERC during a regulatory reset process for approval and inclusion in the RAB for the next regulatory reset.

REGULATORY ASSET BASE for TRANSCO - Expressed in Peso

Exchange Rate Assumption for Forecast Period (peso/US$ at end year)

Philippines Consumer Price Index Change Assumption (% pa over year)

USA Consumer Price Index Change Assumption (% pa over year)

Historical Cost of Regulatory Asset Base Indexed Cost (or Revalued Cost) of Regulatory Asset Base

Sheet A.1 : Opening Regulatory Asset Base.


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APPENDIX B

CAPITAL EXPENDITURE FORECAST TEMPLATES

For the purposes of 4.10 of the RTWR the following templates should be utilized to provide summaries of the capital expenditure forecasts to the ERC. The templates are assumed to link according to Figure B.1.

Sheet 1Summary - Total

Peso NominalCapex Forecast

Sheet 2APeso Nominal

Capex ForecastPeso Component

Sheet 2BPeso Real

Capex Forecast

Sheet 3BUS$ Nominal

Capex Forecast

Sheet 3CUS$ Real

Capex Forecast

Sheet 3APeso Nominal

Capex ForecastUS$ Component

Phil. CPI

US CPI

US$/Peso & Phil. CPI

SUM

Figure B.1 : Development of Capital Expenditure Forecast Summary


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Budget (peso,

nominal)Asset Category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015(a) Transmission Linesi Buildings, civil works and establishmentii Towers and associated linesiii Poles and associated linesiv Underground cablesv Submarine cables including CTS & CS, ellectrode lines & acessoriesvi Easements owned by the Regulated Entityvii Otherviii Spares, spare parts & toolsix Land owned but used for transmission lines

Sub-total Transmission Lines (b) Transmission Substation Componentsi Buildings, civil works and establishmentii Power Transformersiii Circuit breakers & accessoriesiv Instrument Transformersv Protection and control equipmentvi Power compensating equipment, eg: reactorsvii Buswork, power and control cablesviii Otherix Spares, spare parts & toolsx Land owned but used for substations

Sub-total Substation Components(c ) Communication Planti Buildings, civil works and establishmentii Communications plant and infrastructureiii Fibre optic cablesiv fibre optic cable terminal equipmentv Ancilliary infrastructurevi Othervii Spares, spare parts & toolsviii Land owned and used for communications plant

Sub-total Communications Plant(d) System Operationsi Buildings, civil works and establishmentii Control room and control infrastructureiii Ancilliary infrastructureiv Otherv Spares, spare parts & toolsvi Land owned but used for systems operations

Sub-total Systems Operations(e) Metering Equipment Assetsi Market metersii Meters which are not Market meters, Connection assets or Subtransmission assets

Sub-total Metering Equipment Assets(f) Non-Network Assetsi Computers and office equipmentii Plant, tools and equipmentiii Furnature and fittingsiv Commercial buildingsv Land owned but used for non-network assets covers all land value not previously attributedvi Other

Sub-total Non-Network Assets(g) Found Assetsi Assets found between a Regulatory Period and the Subsequent Regulatory Period (*1)Allocated Overheads CapitalizedTotal Capital ExpenditureExchange Rate Assumption for Forecast Period (peso/US$ at end year)Philippines Consumer Price Index Change Assumption (% pa over year)USA Consumer Price Index Change Assumption (% pa over year)Note (*1) : But not related to capital expenditure, and submitted to the ERC during a regulatory reset process for approval and inclusion in the RAB for the next regulatory reset.

Actual (peso, nominal in peso of reporting year)

TOTAL CAPITAL EXPENDITURE for TRANSCO - Expressed in Peso

Forecast (peso, nominal in peso of reporting year)

Sheet B.1 : Capital Expenditure Forecast Summary.


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Budget (peso,








PESO CAPITAL EXPENDITURE for TRANSCO

Actual (peso, nominal in peso of reporting year) Forecast (peso, nominal in peso of reporting year)

Sheet B.2A : Nominal Capital Expenditure Forecast Estimates for Peso

Expenditure.


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Budget (peso, real)

Asset Category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015(a) Transmission Linesi Buildings, civil works and establishmentii Towers and associated linesiii Poles and associated linesiv Underground cablesv Submarine cables including CTS & CS, ellectrode lines & acessoriesvi Easements owned by the Regulated Entityvii Otherviii Spares, spare parts & toolsix Land owned but used for transmission lines







PESO CAPITAL EXPENDITURE for TRANSCO

Actual (peso, real in peso of reporting year) Forecast (peso, real in peso of January 1, 2005)

Sheet B.2B : Real Capital Expenditure Forecast Estimates for Peso Expenditure.


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Budget (peso,








US$ CAPITAL EXPENDITURE for TRANSCO - Expressed in Peso


Sheet B.3A : Nominal Peso Capital Expenditure Forecast Estimates for US$

Expenditure.


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Budget (US$,








US$ CAPITAL EXPENDITURE for TRANSCO - Expressed in Nominal US$

Actual (US$, nominal in US$ of reporting year) Forecast (US$, nominal in US$ of reporting year)

Sheet B.3B : Nominal US$ Capital Expenditure Forecast Estimates for US$

Expenditure.


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Budget (US$, real)

Asset Category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015(a) Transmission Linesi Buildings, civil works and establishmentii Towers and associated linesiii Poles and associated linesiv Underground cablesv Submarine cables including CTS & CS, ellectrode lines & acessoriesvi Easements owned by the Regulated Entityvii Otherviii Spares, spare parts & toolsix Land owned but used for transmission lines







Forecast (US$, real in US$ of January 1, 2005)

US$ CAPITAL EXPENDITURE for TRANSCO - Expressed in Real US$

Actual (US$, real in US$ of reporting year)

Sheet B.3C : Real US$ Capital Expenditure Forecast Estimates for US$

Expenditure.


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APPENDIX C

OPERATING & MAINTENANCE EXPENDITURE FORECAST TEMPLATES

For the purposes of 4.11.1 of the RTWR the following templates should be utilized to provide summaries of the operating and maintenance expenditure forecasts to the ERC. The templates are assumed to link according to Figure C.1.


Peso NominalOpex Forecast

Sheet 2APeso NominalOpex Forecast

Peso Component

Sheet 2BPeso Real

Opex Forecast

Sheet 3BUS$ Nominal

Opex Forecast

Sheet 3CUS$ Real

Opex Forecast

Sheet 3APeso NominalOpex Forecast

US$ Component

Phil. CPI

US CPI


SUM

Figure C.1 : Development of Operating & Maintenance Expenditure Forecast

Summary


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Budget (peso, nominal)

Opex Category and Sub-category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Payroll

Network operations supervision and engineering staffNetwork operations other staffNetwork planning supervision and engineering staffSystems Operations supervision and engineering staffAdministration, human resources, finance, corprate and regulatory staffEasements owned by the Regulated EntitySub-total Payroll

Network RelatedNetwork operationsNetwork maintenancePlant & equipment insuranceSystem operationsWESM compliance (excluding any expenses incurred as the Market Operator)Sub-total Network Related

Non-network RelatedBad debtsInternal & external audit functionsRegulatory liaison & complianceCorporate & central officeIT licenses, operations & maintenanceLease payments (buildings, vehicles, furnature & fittings and otherNet foreign exchange (either loss or gain)Property maintenanceProperty insuranceOther Sub-total Non-network Related

Total Operating & Maintenance ExpenditureExchange Rate Assumption for Forecast Period (peso/US$ at end year)Philippines Consumer Price Index Change Assumption (% pa over year)USA Consumer Price Index Change Assumption (% pa over year)

Forecast (peso, nominal in peso of reporting year)Actual (peso, nominal in peso of reporting year)

TOTAL OPERATING & MAINTENANCE EXPENDITURE for TRANSCO

Sheet C.1 : Operating & Maintenance Expenditure Forecast Summary






Total Operating & Maintenance Expenditure

Philippines Consumer Price Index Change Assumption (% pa over year)

PESO OPERATING & MAINTENANCE EXPENDITURE for TRANSCO


Sheet C.2A : Nominal Peso Operating & Maintenance Expenditure Forecast

Estimates for Peso Expenditure.


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PESO OPERATING & MAINTENANCE EXPENDITURE for TRANSCO

Forecast (peso, real as at December 31, 2010)

Sheet C.2B : Real Peso Operating & Maintenance Expenditure Forecast Estimates

for Peso Expenditure.

Budget (peso,

nominal)Opex Category and Sub-category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Payroll




Total Operating & Maintenance ExpenditureExchange Rate Assumption for Actual or Forecast Period (peso/US$ at end year)

Forecast (peso, nominal in peso of reporting year)

US$ OPERATING & MAINTENANCE EXPENDITURE for TRANSCO - Expressed in Peso

Actual (peso, nominal in peso of reporting year)

Sheet C.3A : Nominal Peso Operating & Maintenance Expenditure Forecast

Estimates for US$ Expenditure.


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Budget (US$,

nominal)Opex Category and Sub-category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Payroll






Forecast (US$, nominal US$ in the reporting year)Actual (US$, nominal in US$ of reporting year)

US$ OPERATING & MAINTENANCE EXPENDITURE for TRANSCO - Expressed in Nominal US$

Sheet C.3B : Nominal US$ Operating & Maintenance Expenditure Forecast

Estimates for US$ Expenditure.

Budget (US$, real)






Forecast (US$, real US$ as at December 31, 2010)

US$ OPERATING & MAINTENANCE EXPENDITURE for TRANSCO - Expressed in Real US$

Sheet C.3C : Real US$ Operating & Maintenance Expenditure Forecast Estimates

for US$ Expenditure.


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APPENDIX D

OPEX-RELATED TAX COST FORECAST TEMPLATES

For the purposes of Section 4.11.2 of the RTWR the following templates should be utilized to provide summaries of the operating & maintenance expenditure (opex) related tax cost forecasts to the ERC, based on a categorization of these taxes into the same categories of opex which give rise to them. The templates are assumed to link according to Figure D.1.


Peso NominalTax Forecast

Sheet 2APeso NominalTax Forecast

Peso Component

Sheet 3BUS$ NominalTax Forecast

Sheet 3APeso NominalTax Forecast

US$ Component


SUM

Figure D.1 : Development of Opex-Related Tax Cost Forecast Summary


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Tax Related Category or Sub-category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Payroll




Residual Uncategorized Taxes, Levies and DutiesFranchise tax Remaining taxes, levies and dutiesSub-total Residual Uncategorized Taxes, Levies and Duties

Total Taxes, levies and duties (other than corporate income tax)Exchange Rate Assumption for Forecast Period (peso/US$ at end year)Philippines Consumer Price Index Change Assumption (% pa over year)USA Consumer Price Index Change Assumption (% pa over year)

TOTAL TAX PAYMENTS for TRANSCO (Other than corporate income tax)


Sheet D.1 : Total Opex-Related Tax Cost Forecast Summary







Total Taxes, levies and duties (other than corporate income tax)


PESO TAX PAYMENTS for TRANSCO (Other than corporate income tax)

Sheet D.2A : Nominal Peso Opex-Related Tax Cost Forecast Estimates for Peso

Payments.


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Total Taxes, levies and duties (other than corporate income tax)Exchange Rate Assumption for Actual or Forecast Period (peso/US$ at end year)

US$ TAX PAYMENTS for TRANSCO (Other than corporate income tax) - Expressed in Peso


Sheet D.3A : Nominal Peso Opex-Related Tax Cost Forecast Estimates for US$

Expenditure.

Budget (US$, nominal)






Total Taxes, levies and duties (other than corporate income tax)


Actual (peso, nominal in peso of reporting year) Forecast (US$, nominal US$ in the reporting year)

US$ TAX PAYMENTS for TRANSCO (Other than corporate income tax) - Expressed in US$

Sheet D.3B : Nominal US$ Opex-Related Tax Cost Forecast Estimates for US$

Expenditure.


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APPENDIX E

CORPORATE INCOME TAX TEMPLATES

For the purposes of Section 4.12.5 of the RTWR the following template should be utilized to provide a summary of the actual corporate income tax related cost incurred by NGCP.


Year 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Corporate Income Tax (CIT)

TOTAL ACTUAL CORPORATE INCOME TAX PAYMENTS for TRANSCO


Sheet E.1 : Actual Corporate Income Tax Costs.

Position Paper for NGCP under RTWR

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