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«ABSTRACT There was a period in the history of electricity rate regulation in the Philippines when the use of a revalued regulatory asset base (RAB) ...»

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THE RATIONALE FOR ASSET REVALUATION IN

THE PHILIPPINE ELECTRICITY SECTOR

By: Helena S. Valderrama, Ph.D.

ABSTRACT

There was a period in the history of electricity rate regulation in the Philippines when the use of a

revalued regulatory asset base (RAB) was rational. This was from the 1980’s to the early part of

the 21st century when the country was struggling with a ballooning public sector deficit and a continuously devaluing currency and when the entire electricity infrastructure was publicly owned and financed mostly by foreign debt. The electricity sector has since been radically restructured and economic conditions in the country have since vastly improved. Yet, electricity rates in the Philippines continue to be among the highest worldwide. This paper argues that among the reasons for the high rates is the continued use of a revalued RAB using the Optimized Depreciated Replacement Cost Method. The ODRC method, as operationalized in the country, produces a value that is almost meaningless from the economic, regulatory, and financial reporting points of view.

Moreover, the method distorts the incentive structure in the industry as it results in wealth transfers from electricity consumers to utility shareholders beyond that which is supposed to be earned by the latter based on its regulatory-prescribed rate of return.

INTRODUCTION

Beginning with the passage into law in 2001 of the Electric Power Industry Reform Act (EPIRA), the Philippines embarked on a comprehensive restructuring of its power industry. From a verticallyintegrated, extensively publicly-owned utility business, the industry was envisioned to be broken down into its main components, have deregulated generation and supply sectors, and be privatized to the extent possible.

EPIRA was passed a decade after a power crisis crippled the country, with households and businesses suffering widespread 4-12 hour blackouts daily for almost 2 years. National Government responded by enjoining the private sector to invest in additional generation capacity through build-operate-transfer and similar arrangements with the National Power Corporation, the government entity solely in charge of generation and transmission at the time. These initiatives successfully solved the problems caused by insufficient generation but also raised electricity rates to levels that eventually caused public outcry.

Expectations were thus high that the overhaul of the power sector that will come with the implementation of EPIRA will finally solve the country’s power sector problems. For most, among the anticipated outcomes were lower electricity charges.

Unfortunately, another decade passed since EPIRA became law, and the problem of high electricity rates continued to plague the country. According to a report,the Philippines has in fact overtaken Japan and already holds the record as having the highest residential electricity rates in the world. It is second to Singapore in terms of commercial rates.1 Diaz, J. (2011), Phl has world’s highest power rates (www.philstar.com) This paper looks into a key input in the rates charged for transmission and distribution services in

the Philippines: the valuation of the rate base. It aims, in particular, to do the following:

 Provide an overview of the rate-setting methodologies for the transmission and distribution

–  –  –

 Analyze the rationale in the use of the optimized depreciated replacement cost (ODRC) method in the valuation of transmission and distribution assets of Philippine utilities

RATE SETTING IN TRANSMISSION AND DISTRIBUTION

EPIRA did not change the status of electricity transmission and distribution as regulated sectors.

These two services accounted for 9% and 18%, respectively, of residential power rates during the period 2003 to 2010 (Valderrama 2011). The rates charged by these sectors are subject to the rules and regulations prescribed by the Energy Regulatory Commission (ERC).

The rate-setting methodologies for transmission and distribution are very similar. Both have been transitioned from a return-on-rate-base (RORB) methodology pre-EPIRA to a performance-based regulation (PBR) methodology. The rate-setting methodologies in both sectors begin with determinations of the annual revenue requirement (ARR) of the affected utility for a regulatory period of 5 years for transmission and 4 years for distribution. The annual revenue requirement

for both sectors has the following building blocks:2

1. Operating and maintenance expenditure (Opex) ERC (2009), Rules for Setting Transmission Wheeling Rates for 2003 to around 2027, sec. 4.5.1; ERC (2009) Rules for Setting Distribution Wheeling Rates for Privately Owned Distribution Utilities Entering Performance Based Regulation (Fourth Entry Point), sec 4.7.1

2. Corporate income tax3

3. Taxes other than corporate income tax

4. Return of capital in the form of depreciation on the regulatory asset base (regulatory

–  –  –

5. Return on capital computed as the weighted average cost of capital (WACC) multiplied to the sum of the regulatory asset base (RAB) and working capital (WC) The ARRs for the regulatory period are then expressed in present value terms using the computed WACC and converted to a maximum annual revenue or MAR (in pesos) for transmission and a maximum annual price cap or MAP (in peso/kWh) for distribution. The MAR and MAP become the bases for charges for the first year of the regulatory period. These initial rates are allowed to adjust automatically in the subsequent years of the regulatory period for, among others, inflation and foreign currency changes. The rates also include incentives (penalties) for meeting (failing to meet) identified performance targets for the regulatory period.





As can be gleaned from the ARR building blocks, the valuation of the regulatory asset base materially affects the returns to the utility that are imputed in electricity rates; namely, the return of capital and the return on capital. Based on the most recent ERC decisions setting the rates for the National Grid Corporation of the Philippines (the concessionaire for the transmission business) and for Meralco (the biggest distribution utility in the Philippines), these 2 components (particularly return on capital) account for the biggest chunk of the ARR at 79% and 54%, respectively (see Tables 1, 2 and 3).

For the second regulatory period of Distribution Utilities, the corporate income tax component of the ARR has been set to zero (Sec 4.7.6, RDWR for Privately Owned Distribution Utilities Entering Performance Based th Regulation (4 Entry Point)) Table 1 – NGCP Revenue Requirements 2010-20154 NGCP Final Determination 22 Nov 2010 Table 2 – Meralco Annual Revenue Requirement 2012-20155 Table 3 – ARR Building Blocks for Transmission and Distribution

–  –  –

Transmission and distribution utilities also follow similar rules in valuing their respective rate bases. In both the transmission wheeling rate guidelines and the distribution wheeling rate guidelines, the ERC requires the use of the Optimized Depreciated Replacement Cost (ORDRC) approach in the valuation of the rate base.

ERC Case No. 2010-069 RC, In the Matter of the Application for Approval of the Annual Revenue Requirement and Performance Incentive Scheme for the Third Regulatory Period (2012-2015) in Accordance with the Provisions of the Rules for Setting Distribution Wheeling Rates (RDWR) as Amended – Manila Electric Company, Applicant.

The diagram below presents an overview of the valuation process6. In asset optimization (step 3), the maximum planning horizon prescribed is 5-15 years depending on the nature of the asset.

Asset optimization is undertaken as utilities are required to put up the necessary infrastructure to meet not just current electricity demand, but forecast demand over the prescribed planning horizon. However, utilities must be prevented from overbuilding, over-engineering, or providing for unnecessary excess capacity in their rate bases.

Step 2 is the more “contentious” part of the valuation process, as it prescribes the determination of replacement costs for the assets included in the rate base.

ERC (2010), Valuation Handbook for Optimized Depreciated Replacement Cost Valuation of System Fixed Assets of Privately Owned Distribution Utilities Operating Under Performance-Based Regulation (Third Regulatory Period) In the current rules for transmission, the gross current replacement cost may be established using

three methods:7

1. Indexation method – historical costs are adjusted for inflation using suitable indices (e.g.,

–  –  –

2. Replacement cost method – establishing the recent costs of similar assets

3. Modern equivalent asset (MEA) method – current market buying price, current reproduction or replacement cost of a “modern equivalent asset”, defined as “an asset that, in the normal course of a transmission entity’s business, would be used to replace an

–  –  –

For distribution, the modern equivalent asset method is prescribed.9 For commonly used distribution fixed assets, a list of standard replacement costs of MEA was provided as of 31 December 2009. The values therein were supposed to be inflation-adjusted for use in succeeding years using the consumer price index (CPI). For assets not in the provided list, the utility is to

engage a “valuer” to determine the MEA. The latter should be based on an asset that:

1. Has an equivalent service potential to the existing asset

2. Can be constructed or purchased at the time of valuation with current technology; and

3. Has the lowest lifetime cost.10 In ERC Case no. 2005-041 dated 12 July 2010, the ERC distinguished between the ODRC methodology and the valuation basis for the regulatory asset base used under the RORB regime, which likewise was a form of replacement cost (see table below).

ERC (2009), Asset Valuation Guidelines for NGCP Assets, p 14 Ibid, p 15 ERC (2010), Draft Valuation Handbook for Optimized Depreciated Replacement Cost Valuation of System Fixed Assets of Privately Owned Distribution Utilities Operating Under Performance-Based Regulation (Third Regulatory Period) Ibid, p 20 It can be observed from the above that under both regimes, the rate base was allowed to be remeasured or revalued based on current or replacement costs at the time of the rate application.

Optimization over a specified planning horizon is explicit under the PBR methodology, although RORB regulation would have also employed mechanisms to ensure that utilities were not reimbursed for inefficient and unnecessary capital costs.

It is also clear that the utilities regulation in the Philippines has departed from the use of historical or acquisition costs in the valuation of the rate base even before EPIRA was passed. Anecdotal evidence traces the reason for this to the fact that when the electricity industry was completely government owned in the past, financing of the infrastructure was done mainly through foreign currency-denominated loans. As the Philippines had a history, until recently, of a weaker currency vis-à-vis its creditors, servicing the debts required bigger and bigger amounts of the local currency which needed to be obtained through rate adjustments.

An apparent point of difference between the 2 regimes is the prescription under the PBR methodology that the reappraised asset base be based on the “lower of replacement cost or modern equivalent asset (MEA) value”. As observed earlier, however, under present rules, utilities are referred to a list of MEA values for many assets as of 31 December 2009 which amounts are supposed to be adjusted via an index for use in succeeding years. Thus, unless replacement costs of the existing assets are to fall, the gross valuation of the rate base will be increasing throughout the regulatory period in both the PBR and RORB regimes.

ANALYSIS OF THE USE OF REPLACEMENT COST IN RATE BASE

VALUATION

This section presents and analyzes arguments for and against the use of depreciated replacement cost (DRC) in rate base valuation. Literature that identifies serious flaws in the theory and use of the DRC methodology in electricity rate-setting is presented. Financial accounting theory and standards are drawn from to show that depreciated replacement cost is an invalid surrogate of fair value, a measurement model that is increasingly favored by standard setters and financial statement users due to its consistency with firm valuation theory. A simulation exercise is undertaken to show the effects of using DRC on a utility’s returns. The analysis shows that DRC valuation enables the incumbent utility to earn higher than its regulation-prescribed rate of return.

Thus, the DRC method achieves no meaningful economic and financial purpose and serves only to unnecessarily inflate electricity prices to the disadvantage of consumers.

REGULATORY AND ECONOMIC JUSTIFICATION OF REPLACEMENT COST VALUATION

The use of optimized depreciated replacement cost (ODRC) in the rate-setting regime for the transmission business in the Philippines is patterned after the regulations in Australia and New Zealand, rather than those in the U.S. and U.K., where the regulatory asset base continues to be valued and depreciated at acquisition cost11. The main justification for the use of ODRC is gleaned from the following excerpts taken from valuation “handbooks” promulgated by the ERC for the

transmission and distribution sectors:

“The ODRC method measures the economic value of system assets to an entity on the basis that the entity operates in an efficient manner that is sustainable over time and is not able to generate monopoly income. The method determines a hypothetical value of the assets which is a surrogate for market value in circumstances where it is not possible to determine values for specialized assets using a market comparison approach.



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