Draft NERSA Consultation Paper Multi Year Price ... Rule Changes... · Valuation of the regulatory...

NERSA MYPD2 Consultation paper PE Cost adjustment, CAPEX and re-opener

IDMS.40244 No v1 of 36

Draft NERSA Consultation Paper

Multi Year Price Determination 2 (MYPD 2): Proposed Rule Changes



Table of Contents

1 Introduction .................................................................... 5

2 Primary energy cost mechanism ................................. 5

2.1 Objectives to be achieved through the mechanism ................................. 6 2.2. Suite of available PE cost pass-through mechanisms ............................. 7

2.2.1 Full pass-through of power purchase costs ..................................... 8 2.2.2 Review of power contracts .............................................................. 8 2.2.3 Administratively set benchmarks ..................................................... 9 2.2.4 Mandated competitive procurement ................................................ 9 2.2.5 Market benchmarks ....................................................................... 10

2.3 Analysis of Eskom‟s primary energy options and the pass-through balancing account .................................................................................. 10

2.3.1 Pass-through mechanism for IPP purchases ................................ 12 2.3.2 Non-coal generation costs (e.g. OCGT) ........................................ 12 2.3.3 Coal procurement mechanism ....................................................... 14 2.3.4 Pass-through of other primary energy costs .................................. 15

3 Capital expenditure cost variance mechanism ........ 15

3.1 Current approach within MYPD1 ........................................................... 15 3.2 Eskom‟s proposed CAPEX adjustment mechanism ................................... 15 3.3 Views on Eskom‟s proposals .................................................................... 17 3.4 Proposed approach .................................................................................. 18

4 MYPD correction factor and trigger for re-opening . 19

4.1 Background on the creation of the re-opener trigger ............................. 19 4.1.1 Correction factor and re-opener trigger ......................................... 19 4.1.2 Stakeholder inputs to first consultation paper ................................ 20 4.1.3 Existing re-opener rule/approach ................................................ 20

4.2 Correction factor as re-opener trigger .................................................... 21 4.3 Eskom‟s proposed trigger mechanism ................................................... 22 4.4 Earnings band as re-opener trigger ....................................................... 22 4.5 Conclusions on re-openers .................................................................... 24

4.5.1 Trigger behaviour .......................................................................... 24 4.5.2 Re-openers .................................................................................... 25 4.5.3 Practicality of re-opening a determination ..................................... 27 4.5.4 Joint or separate Eskom business re-openers .............................. 28 4.5.5 Recommendations......................................................................... 30

5 Valuation of the regulatory asset base (RAB) ....... 30

5.1 MYPD 1 approach ................................................................................ 30 5.2 Eskom‟s proposed regulatory asset base valuation method .............. 31 5.3 Alternative methods for measuring the RAB ....................................... 31 5.4 Views on Eskom‟s proposal and other valuation methods ................. 33 5.5 Proposed approach for asset valuation ............................................... 34

6 Consultation process .................................................. 35



List of Tables Table 1: Comparison of PE costs in MYPD plans to revised Eskom applications . 5 Table 2: Scenarios of applying the coal pass-through formula ........................... 15 Table 3: Sample calculation of allowed revenue and correction factor ............... 21 Table 4: Options for re-opener - various scenarios ............................................. 26 Table 5: Ringfencing options for MYPD2 revenue controls ................................. 29

List of Figures

Figure 1: Earnings band description ................................................................... 23



ABBREVIATIONS

CAPEX Capital Expenditure

CECA Capital Expenditure Carryover Account

CF Correction Factor

EB Earnings Band

IPART Independent Pricing and Regulation Tribunal

IPPs Independent Power Producers

KSACS Key Sales and Customer Services

MEA Modern Equivalent Asset

MEV Modern Equivalent Valuation

MYPD Multi-Year Price Determination

NERSA National Energy Regulator of South Africa

OCGT Open Cycle Gas Turbines

OPEX Operating Expenditure

PBR Performance Based Regulation

PE Primary Energy

PPAs Power Purchase Agreement

RAB Regulatory Asset Base

REDs Regional Electricity Distributors

ROA Return on Asset

ROR Rate of Return

WACC Weighted Average Cost of Capital

WEPS Wholesale Electricity Pricing System



1 Introduction On 30 April 2007 Eskom applied to the Energy Regulator requesting a change to the rules within the Multi Year Price Determination. Specifically Eskom‟s request was focused on the following areas of the MYPD:

1) Primary Energy cost variances;

2) Variances on Capital expenditure; and

3) Rules on a trigger for a re-opener.

On 20 December 2007 the Energy Regulator decided that the rule changes applied for by Eskom be treated entirely in the second multi year price determination (MYPD 2) rules review process. On 02 September 2008 Eskom submitted a regulatory asset base (RAB) rules review proposal that is different from the one submitted on 30 April 2007. Over and above their initial proposal they are now proposing a rule change on the evaluation of the RAB. This consultation paper seeks to solicit stakeholders views on the 4 items mentioned above in order to incorporate the proposals into the overall MYPD2 mechanism. The other building blocks of the mechanism have already been consulted upon in 2006.

2 Primary energy cost mechanism The first Multi-Year Price Determination (MYPD) of Eskom was concluded and implemented with effect from 1 April 2006 to 31 March 2009. However, on 30 April 2007 Eskom applied to the Energy Regulator for a review of the original determination due to variances between the forecast costs in the MYPD plans and the actual costs. The determination was therefore reviewed and a new price increase of 14.2 % was approved by the Energy Regulator. On 17 March 2008 Eskom again applied to the Energy Regulator for a review of its allowed revenue due to increasing primary energy costs. The table below demonstrates the variance between Eskom‟s original MYPD application and subsequent applications that were received for review:

Rm 2006/7 2007/8 2008/9 Total MYPD

Original MYPD PE cost allowed1 11 066 12 593 14 811 38 470 Actual and projected PE costs2 13 039 18 847 23 052 54 938 Variance 1 973 6 254 8 241 16 468 Percentage variance 17.8 % 49.7 % 55.6 % 42.8 % Table 1: Comparison of PE costs in MYPD plans to revised Eskom applications

1 Original MYPD plan in 2006

2 Figures as per Eskom application for PE cost review in April 2008



The reasons for such variances may be summarized as follows:

1. fuel price volatility – due to changes in the price of coal, gas etc. The effect would be a direct change in the cost per kWh of energy generated;

2. fuel mix uncertainty – at the margin the type of power stations used vary to original planned stations at time of application. As production costs of each station differ, this will affect the average price of fuel;

3. energy demand/volume uncertainty – changes in demand that may come due to economic growth or any other factor demanding additional energy to be generated; and

4. fuel burn rate efficiency uncertainty – changes in envisaged coal quality which leads to burning of more coal for same quantity of electrical energy.

It was for these reasons that NERSA saw it fit that some risk management device be developed to mitigate against those costs considered to be unstable and outside the full control of Eskom‟s management and those that are difficult to predict at the time of MYPD planning. In its decision on 18 June 2008 for the second MYPD review, the Energy Regulator decided as follows with regard to the risk management device: “That a mechanism be developed by the Energy Regulator to take into account unforeseen changes in primary energy costs and other costs. The mechanism must also take into account the efficient costs; the prudency with which the costs are incurred, Eskom’s ability to control these costs and its ability to predict such costs at the time of the application.” However, even after having considered the above reasons and resultant risk to Eskom, it is also necessary that the setting of any pass-through mechanism should not provide perverse incentives for the supplier not to efficiently manage its planning and procurement processes.

Question to stakeholders # 1

Stakeholders are asked to comment on the introduction of a risk sharing mechanism that will account for unforeseen costs within the MYPD especially with regard to fuel procurement.

2.1 Objectives to be achieved through the mechanism

While there are conflicting objectives in any pass-through mechanism for power cost purchases, there are minimum and common objectives that any mechanism must strive to achieve or at least strike a balance where conflict exists. The objectives to be achieved by the perceived mechanism within the MYPD are mentioned below and will assist in the development of the pass-through mechanism to be adopted by NERSA for the regulation of Eskom. The mechanism must:



1. provide incentives for efficient energy procurement;

2. reduce electricity price volatility to customers;

3. allow Eskom to recover prudent primary energy costs;

4. provide cost reflective price signals for electricity demand to react;

5. provide incentives for suppliers to establish long-term energy supply contracts;

6. clear, transparent and objective mechanism;

7. reduce the potential for self-dealing and collusion between primary energy

suppliers and the regulated entity;

8. minimise the number of reviews by the Energy Regulator;

9. efficiently allocate risk to Eskom and customers with due consideration of the entity being more able to manage the risk; and

10. provide incentives for accurate forecasts of costs and minimize perverse

incentives in this regard. At times the conflicting nature of the above objectives is recognized and in the development of the mechanism, this is kept in mind at all times. An effort to strike a good balance on these objectives is made.


Stakeholders are asked to comment on the above objectives to be achieved by the risk sharing mechanism.

2.2. Suite of available PE cost pass-through mechanisms

In the development of the mechanism various options were considered as applied in other countries around the world. The sections below consider the various options of structuring the pass-through cost mechanism. It is noted that the various options apply differently for different environments and for different purchase mechanisms. Also it should be noted that Eskom has various purchasing options and the mechanism will have to consider all such options. It may be possible therefore, that one option may be selected from the purchases within the coal environment and a different one for purchases from other fuel sources. It will also be necessary that the overall mechanism be built in such a way that it does not give perverse incentives to Eskom to prefer purchasing from



one market over another without adequate economic reasons (e.g. where one market is allowed full pass-through). The various mechanisms are listed below3.

2.2.1 Full pass-through of power purchase costs

Full pass-through of power purchase costs are usually considered when it is the opinion of the Regulator that the entity being regulated has limited control over the volumes, prices, risk allocation or choice of power procurement. If this is determined to be so then the Regulator will allow full pass-through of all power purchase costs. Generally these would be applicable where a single buyer model has been adopted and where vesting contracts exist. It should still be noted that even when there is full pass-through allowed, there would generally be a lag between the time when variances occur and when the adjustment is made. Generally this is done in order to avoid price volatility to customers and to also avoid inflationary spikes. However, even so the lag should not be too long as to lead to viability problems for the supplier. Full pass-through mechanisms are applied mainly in most USA utilities, Brazil, Argentina, Panama, Nicaragua, Guatemala, El Salvador, Hungary, and Northern Ireland with variations from each of the above countries. Variations to this mechanism include:

“Prudent” expenses in cost-plus regime

Vesting contracts

Purchases as a single buyer

2.2.2 Review of power contracts

With this mechanism, the Regulator reviews the existing power purchase contract and on this assessment, determines the level of pass-through to retail customers i.e. the Regulator may or may not allow energy costs to be recovered from end-use customers. Ex ante (prior to signing of the contract) reviews are made to ensure that the contract complies with the applicable laws or contracting guidelines (e.g. cost recovery mechanism) and will be awarded a full pass-through status.

3 This research is mainly based on Distribution companies purchasing their power on contract. This

compares to Eskom’s purchases of primary energy.



Ex post (after the contract has been signed) reviews usually occur when there is an allegation of corruption of incompetence in the awarding of a contract and are usually very contentious. There have been instances where such reviews resulted in the terms and conditions of the contracts being amended to be in line with law and guidelines. Ex post reviews are generally regarded as undesirable as they generally look at issues of incompetence and inefficiency without providing for penalties for failures to adopt best practice or incentives to reward such. Examples of power contract reviews are at Guatemala, Panama, Nicaragua (also mentioned above), Massachusetts and Nevada, California and India with some variations.

2.2.3 Administratively set benchmarks

In this mechanism, the Regulator defines benchmark costs using administratively established estimates of investment and operating costs. The buyer is then allowed to pass-through prices up to the benchmark. Anything above the benchmark price would then be disallowed as a pass-through. There is a potential problem with this method in that if these benchmarks are too low, then the buyer (i.e. Eskom) will not be allowed to recover its costs of purchasing power. Where these are too high, they will result in windfall gains for the supplier. Examples of administratively set benchmarks can be found in Brazil (current) and the USA (1978). Variations include:

Benchmarks based on regulator‟s estimates of long-run marginal cost of new generation

Benchmarks based on distributor‟s (in this case Eskom‟s) “avoided costs”

2.2.4 Mandated competitive procurement

In this case the Regulator requires that suppliers (Eskom) buy some or all of their requirements through a competitive and transparent procurement process with the hope that this will result in cost-effective purchases. Under this practice the full resultant costs are allowed as pass-through. There are two types of contracts in this mechanism i.e. Physical contracts and financial contracts. These are generally found in Florida, Panama, Guatemala, Nicaragua and New Jersey. Available options are Physical and Financial contracts.



2.2.5 Market benchmarks

This method uses the average actual spot market price estimates as a benchmark and allows pass-through of all costs within the benchmark prices. This allows for an incentive for good procurement purchases by the supplier as the supplier is allowed to keep all or some of the difference and if he procures at higher prices he bears all or some of the additional costs. The calculation of the spot prices may be ex ante or ex post. This method is used in Chile, Peru, El Salvador, Bolivia, Argentina, Brazil, Colombia and The Netherlands with variations on application. Options include spot markets, contracts and a mixed variation of these options in a multi-market environment.

The above mechanisms may or may not be applicable in one country and may offer some benefits to one country without necessarily doing so in another. It is very important that prior to selecting the best option, a study of the industry structure of the specific country be taken into account. It is also important to note that more than one method may be applied in one country e.g. one method may be applicable in South Africa for Eskom‟s purchases from the long-term coal contracts and a different one for the purchases from the “spot market” and from Independent Power Producers (IPPs). Care should be taken in the selection of the “right” mechanism for each purchased option. Also it is necessary to accept that any method that has been selected may change as the market conditions change. Principal to the choice of a method is consideration of objectives to be achieved by the method. It is NERSA‟s view that a combination of various methods should be used for the South African market depending on Eskom‟s primary energy purchase options and its ability to control and predict the variances.


Stakeholders are asked to comment on the above options for a primary energy pass-through mechanism and to state their preference to the best option to be applied for the South African Market. Stakeholders are further asked to comment on whether one mechanism must be applied for all primary energy purchase options (coal, gas, IPPs, etc) or whether a different method be applied for each purchase option.

2.3 Analysis of Eskom’s primary energy options and the pass-through balancing account

To develop an appropriate mechanism for the Eskom primary energy variances, it is necessary that Eskom‟s purchase options be analysed as any mechanism must suit the market for which it is designed. In order to determine the total primary energy costs to be passed through it will be necessary that a balancing



account be created for the accumulation of all purchase cost variances (negative and positive) for each market and that only the net figure be allowed as a pass-through i.e. a consolidated pass-through amount be determined. The balancing account will be referred to as Regulatory Asset Account4 and shall be used as follows:

i. The Regulatory Asset Account shall be used as a repository for PE cost pass-through amounts to avoid line-by-line pass-through of costs;

ii. The Regulatory Asset Account will be created towards the end of Eskom‟s financial year (covering the 3 months prior to year end) with actuals for the 3 months and projections to year end;

iii. The Regulatory Asset Account balance will be measured as a percentage of total allowed revenue ;

iv. If the Regulatory Asset Account balance is less than or equal to 5% of total revenue, then no pass-through shall be allowed;

v. If the balance is between 5 % and 10% the pass-through shall be allowed without a need for full stakeholder consultation process;

vi. If the balance is greater than 10 % of the revenue then there shall be a need for full stakeholder consultation process before any pass-through is allowed;

vii. Whilst the proposal is to use the account towards year-end, there is a need to have this account updated quarterly so as to use it for regular alerts to customers of any possible adjustment in the coming year;

viii. Eskom, will on a quarterly basis, present the Energy Regulator with possible adjustments based on the mechanism, the costs to date and the projections to year-end;

ix. The Energy Regulator will then review Eskom‟s submission and have it published on both Eskom and NERSA websites; and

x. Because the review is done prior to year-end and before the audit of Eskom‟s accounts has been performed, a further review for correctness of information will be performed upon receipt of audited statements from Eskom.


Stakeholders are asked to give their views on the creation and management of the Regulatory Asset Account and the publishing of regular alerts of possible pass-through adjustment in the next financial year. Views are also requested on the use of the 5 and 10 % dead bands for the pass-through.

Eskom‟s primary energy cost purchases are driven mainly by its procurement arrangements which are mainly as described below

4 The Regulatory Asset Account will be debited or credited with both positive and negative variances



1. Purchases from Independent Power Producers (IPPs) based on Power Purchase Agreements (PPAs);

2. Non-coal technology self-generation e.g. Open Cycle Gas Turbine (nuclear and hydro not included here);

3. Coal technology self-generation5 a. Cost plus contract purchases b. Fixed price contract purchases c. Above-contract volume purchases within the contract d. Short-term/spot coal purchases

4. Nuclear fuel self-generation 5. Hydro powered self-generation 6. Other costs e.g. water treatment, start-up fuel, coal handling costs etc.

It is accepted that each of the above has a unique risk profile and may need a different mechanism designed to cover such risks also bearing in mind the objective of allocating the risk to the entity more able to mitigate the risk.

2.3.1 Pass-through mechanism for IPP purchases

The mechanism for IPP purchases will be structured as follows:

1. Purchases from IPPs will be allowed as a full pass-through in line with the Single Buyer model as approved by Cabinet;

2. However, to mitigate the risk of inefficient procurement, the Energy Regulator will have an ex ante (prior to signing) review of power purchase agreements between Eskom and IPPs, as envisaged in the Cabinet memo;

3. The pass-through will still be under a review to determine the efficiency and prudency with which they have been incurred above the MYPD allowance;

4. The variances, together with reasons therefore, will be presented to NERSA 9 months prior to year-end based on actual cost for 9 months and projections to year-end; and

5. The figure as determined after review by NERSA will be deposited into the Regulatory Asset.


Stakeholders are asked to give their views on the proposed pass-though mechanism for IPP purchases.

2.3.2 Non-coal generation costs (e.g. OCGT)

5 Includes coal transport costs



The costs of running OCGT and similar plants with high fuel costs and which are operated in unpredictable emergency situations is probably the biggest risk facing not only Eskom but the entire country. OCGT costs variances and volatilities are expected to be high and much outside the control of Eskom. Changes to original plans can be caused by changes in the cost/price of fuel and changes in the volumes to be delivered from such plants. The design of the pass-through mechanism for OCGT plants considers these potential changes: Changes to the cost of fuel Where variances are caused by changes to the cost of fuel, a full pass-through will be allowed but limited to volumes as presented with the MYPD application and as allowed by the Energy Regulator i.e. the pass-through value will be equal to OCGT Production Volumes in MYPD production plan x the actual price of fuel. This pass-through will only be allowed after consideration of risk mitigation strategies available to Eskom. One of the ways to manage the volatility of uncontrollable costs is by entering into hedging contracts against these costs. However, hedging itself has huge risks for the entity and its customers. NERSA‟s view is not to prescribe hedging to Eskom but to expect Eskom to be prudent in the management of its costs.


Stakeholders are asked to provide their views on using hedging contracts to manage the volatility of costs and whether the Energy Regulator should be involved in such decisions.

Changes to planned volume output from OCGT Eskom is expected to have some control over the utilization of its OCGT plants albeit limited based on some constraints within the entire system. The mechanism for such variances will be as follows:

Eskom will present NERSA with its production plans on the planned utilization of the OCGT plants during the MYPD duration;

Quarterly Eskom would then provide NERSA with actual utilization and explanation of any major deviation from original plans;

NERSA would then review the explanations and where considered prudent allow for pass-through.

NERSA does not intend to place any limitations on load factors of OCGT plants but would want to ensure that these are run only when necessary after due consideration of other available options as prescribed in the Grid Code. Where this cannot be demonstrated to the satisfaction of the Energy Regulator, the resultant costs will not be allowed as pass-through.




Stakeholders are asked to give their views on the proposed mechanism for the running of the OCGT plants and the proposed pass-through mechanism thereof.

2.3.3 Coal procurement mechanism

The mechanism for coal procurement will be structured as follows:

1. Coal will be treated as a single cost centre without differentiating between the various coal sources (i.e. cost plus contracts, fixed price contracts etc.) – coal purchases is seen as a portfolio to be managed using various options;

2. Eskom will however, submit a full breakdown of coal procurement and consumption plan and costs to the Energy Regulator with MYPD application (similar to current practice)

3. The Regulator will analyse the plans and approve an average R/ton cost of coal for each of MYPD years. This price will then become the “benchmark” cost6;

4. Towards the end of each year i.e. after 9 months from year-start, Eskom will submit its actual year-to-date costs with projections to year end;

5. NERSA would then compare the actual (projected) R/ton cost to the benchmark cost using a Performance Based Regulation formula that calibrates incentives and penalties for performance

a. This requires that gains and losses resulting from good or bad procurement be shared among Eskom and its customers

b. Sharing will depend on the basic rule that “the risk will be allocated to the entity more able to manage such risk”

6. A weighted alpha will be set sharing the risk between Eskom and its customers – alpha being any number between 0 and 1;

7. The PBR formula will be

Maximum amount to be allowed for pass-through = Alpha x actual cost + (1 – Alpha) x Benchmark cost

The amount determined will also be deposited into the Regulatory Asset account. Below is an illustration of the determination of coal pass-through costs using the above PBR formula:

1. Assume a benchmark price set by the Regulator at R120/ton 2. Assume scenarios as follows:

a. Scenario 1: Actual price = R125/ton; alpha = 0.4 b. Scenario 2: Actual price = R125/ton; alpha = 0.7 c. Scenario 3: Actual price = R117/ton; alpha = 0.4 d. Scenario 4: Actual price = R117/ton; alpha = 0.7

6 In determining the Benchmark costs NERSA will use the information contained in the NIRP, international

coal prices and an analysis of Eskom’s coal purchase plans



Assumed actual

average coal cost

Assumed alpha

Calculated price

Resulting Pass-

through cost

(R/ton)

Scenario 1 125.00 0.4 122.00 2.00

Scenario 2 125.00 0.7 123.50 3.50

Scenario 3 117.00 0.4 118.80 -1.20

Scenario 4 117.00 0.7 117.90 -2.10 Table 2: Scenarios of applying the coal pass-through formula

The resulting Pass-through cost (R/ton) will be used calculate the total allowed pass-though cost by multiplying it by the actual coal purchase volumes.


Stakeholders are asked to give their views on the treatment of other primary energy costs.

2.3.4 Pass-through of other primary energy costs

The other primary energy costs (nuclear, hydro, other costs) are considered to be stable and less risky and are therefore not allowed as pass-through. It is considered that Eskom must be able to reasonably accurately forecast these costs.


Stakeholders are asked to give their views on the treatment of other primary energy costs.

3 Capital expenditure cost variance mechanism

3.1 Current approach within MYPD1

The impact on depreciation and return stemming from capital expenditure timing differences are reconciled for the next control. Capital cost differences from unplanned projects, cancelled projects or capital cost increase or decreases are taken into account in the regulatory asset base of the next control.

3.2 Eskom’s proposed CAPEX adjustment mechanism



Eskom proposes that timing and cost based capital expenditure variances be recovered by way of adjustment to the revenue allowance during the MYPD as long as NERSA found them to be prudently incurred. Eskom further proposes that a balancing account be kept whereby annual variances in return on capital and depreciation due to variance in capital expenditure is recorded and accumulated, and that if that accumulated balance is greater/less than 2% of revenue allowed for that year, a review process will be triggered upon Eskom‟s application, such variance in return on capital and depreciation would be reconciled by way of adjustment to the revenue allowance and tariffs for the following year. If the balance is to the favour of customers, NERSA will direct Eskom to initiate the review if Eskom has not already done so. If at the end of MYPD 2 the balancing account has not triggered an adjustment to the revenue allowance and tariffs, the full balance would be set off against MYPD 3 revenue allowance. Eskom‟s proposed rule changes for MYPD2 capital expenditure adjustment mechanism are follows:

1. Prior to each MYPD, Eskom will submit a capital expenditure plan as part of its MYPD revenue application (as is currently done) for approval by NERSA.

2. Prior to the end of each financial year during the MYPD (i.e. after nine months of a given financial year), Eskom will provide NERSA with a report of actual Year-to-Date capital expenditure and with projections for that full year. Variances in return on capital and depreciation amounts stemming from (projected) variances against the original capital expenditure plan for that year (timing and cost based) will be placed in the balancing account (positive or negative amounts)

3. If the balancing account (i.e. annualised amounts of return on capital and depreciation stemming from the variance in capital) is 2% (plus or minus) or greater of Eskom‟s allowed revenue for the year, Eskom will lodge an application for cost adjustment for implementation during the following year. This will be done whether the amount is positive or negative.

4. Noting that Eskom would need to provide NERSA with an application for adjustment prior to obtaining full year actuals for the preceding year, the variance against forecast for that preceding will be based on 9 months actuals and three months projections to the year end.

4.1. Any error stemming from the last three month projections against full year end actuals will be reconciled as part of the next year‟s adjustment to the balancing account.

5. If at the end of MYPD 2 the balancing account has not triggered an adjustment, the full balance would be fed into the MYPD 3 revenue allowance



To ensure that efficient costs of supply are recovered by Eskom under the capital expenditure mechanism, the following is required:

1. If the adjustment is triggered, Eskom will provide NERSA in the application for cost adjustment a reconciliation report, as well as a supplementary final reconciliation report once year end data is available (both independently audited)

a. NERSA will review any other aspects of variance in Primary Energy costs it deems relevant in review of the prudency of expenditure.

2. NERSA will have the discretion to review the reports and disallow cost adjustment if they are deemed to be not prudent. Disallowed cost adjustment would be subtracted from the balancing account

3. Subject to prudency review and any relevant disallowed costs, the rand value of the balancing account (subject to meeting the threshold requirement) would be rolled into allowed revenue and tariffs in the first financial year immediately following submission of the application.

4. If the adjustment is triggered, Eskom will provide NERSA with the updated capex plan for the following year and provide details where it varies from the previous year‟s plan.

3.3 Views on Eskom’s proposals

In principle Eskom should be able to benefit from any efficiency gains compared with the estimate and absorb any shortfall from cost overruns. Eskom‟s proposed method of adjusting for timing and costs difference involves a pass-through of capital expenditure costs annually, with significant reporting and auditing of performance after expenditure was incurred (prudence reviews). We recognise that there would be certain variances during the MYPD due to unforeseen events but we don‟t foresee a further acceleration of capital expenditure. The mechanism as proposed may defeat some key objectives of the MYPD i.e. reasonable tariff stability and smoothed changes over time, good balance of commercial risk, efficiency incentives, simplicity and understanding of application, and consistency between controls. Planning and execution of the capital expenditure programme is an area in which Eskom must have greater influence because it is less volatile than other building blocks of the MYPD, especially Primary Energy. We maintain that Eskom‟s costs and timing risks were sufficiently covered within the current MYPD mechanism in that Eskom is required to report to NERSA six monthly on its capital programme, providing information on variances arising in terms of both cost and timing. Upon receipt, NERSA will assess the reports and quantify Eskom‟s exposure (additional expenses stemming from capital expenditure timing and cost differences) and reconcile the RAB and associated returns for the next control period. However, we recognize the risk



of the balance being too big and therefore resulting in possible higher increases in the next period.

3.4 Proposed approach

Eskom must continue to report six monthly to NERSA on its capital expenditure programme, providing information on timing and cost variances. After reviewing the reports NERSA will record all efficient capital expenditure above or below the approved amount on the capital expenditure carryover account (CECA) and the Regulator should allow Eskom to recover/payback the entire under/over recovery in the next MYPD7. This effectively removes from Eskom any potential windfall losses or gains should the approved capital expenditure differ from the actual expenditure and also ensure that the actual return on assets is consistent with allowed return. For any under expenditure compared to forecasted capital expenditure, the value of the RAB will be adjusted downwards for investments not undertaken and the revenues in the next MYPD will be adjusted to compensate for the return earned on unused funds in the previous MYPD, for over expenditure compared to forecasted capital expenditure, the balance would be added to the RAB at the start of the next MYPD. NERSA recognizes that carrying over costs incurred from one MYPD to the other will distort the next MYPD but the application of carryover mechanism will equally apportion the risk and benefits due to forecasting errors.

Question to stakeholders # 10 Stakeholders are asked to comment on the treatment of differences in the investment profile i.e. forecasts used for revenue setting, and on how the RAB should be adjusted for actual expenditure.

Question to stakeholders # 11 Stakeholders are asked to comment on how the risks of cost overruns and under expenditure, delays and acceleration of projects should be apportioned between Eskom and customers, and under which circumstances those must be considered.

Question to stakeholder # 12 Stakeholders are asked to comment on the relevance/irrelevance of the introduction of the capital expenditure carryover account to track capex variances, and if supported how it must me administered.

7 The MYPD period is 3 years (1 April 2009 – 31 March 2012)



4 MYPD correction factor and trigger for re-opening

4.1 Background on the creation of the re-opener trigger

As with the Primary Energy and CAPEX variance pass-through mechanisms discussed above, the request for a rule on a trigger for re-opening the MYPD was one of the proposals included in Eskom‟s application for rule changes and the 18.7 % price increase. Eskom made proposals on the rules to be applied for re-opening the MYPD and these are discussed here together with international practice in order to determine a proposal for the MYPD2 mechanism.

4.1.1 Correction factor and re-opener trigger

The MYPD mechanism is built on the premise that the opening correction factor

is zero, but each projection after the determination will start to see an estimate of

the year-end correction to carry forward. The mechanism allows an interest rate

(prime) to apply to any under or over recovery. The addition of a surcharge over

prime to apply to over recovery was considered in the first consultation paper to

incentivise Eskom to make its estimates more accurate. This surcharge is not

considered necessary in this consultation.

In MYPD1, NERSA set parameters for the correction factor so that it can ask for

explanations and re-open the control if the under or over recovery becomes too

great. The MYPD mechanism requires that the estimated level of the correction

factor be assessed and reported periodically such that this parameter can be

checked.

It is recommended that the correction factor be retained as a re-opener trigger for

MYPD2, in order for the Energy Regulator to review the impact of large

adjustments to allowed revenue on tariffs. As protection against very large

variations in capital expenditure, arising from the current unstable markets, an

earnings band trigger could be used in parallel so that allowed revenue can be

reviewed when Eskom‟s earnings deviate by more than one percent from the

target earnings (WACC). If either of the triggers exceeds a threshold level the

Energy Regulator will review or re-open the determination.

The implications of re-opening the determination are discussed in paragraph

4.5.3. The Energy Regulator requires that the triggers only operate under

exceptional circumstances and that the risk of re-opening be mitigated with

appropriate measures.



4.1.2 Stakeholder inputs to first consultation paper

In the first MYPD2 consultation paper (June 2006) stakeholders were asked for their views on the adequacy of the simple correction factor approach to revenue variances or whether more complex alternatives should be utilised, and on the use of the balances on the correction factor as a guide to any need to re-open the determination before its conclusion.

Stakeholders responded that the application of a simple correction factor to revenue variances is not considered adequate in a volatile environment and that the correction factor should be more transparent.

The correction factor is defined as the difference between the base allowed revenue8 and the actual revenue that Eskom recovers. If the impact of volume variances on Eskom‟s actual revenue recovery is small, the actual revenue will be almost equal to the base allowed revenue. The correction factor will thus be equal to the MYPD mechanism‟s adjustments to the base allowed revenue

In this consultation paper an approach is proposed whereby prudently incurred variances in primary energy cost will be passed through by the MYPD mechanism. By allowing the pass-through of these variances, the cost volatility is transferred to the allowed revenue, thus increasing the correction factor volatility.


Stakeholders are asked to comment on the increased volatility that is introduced to the correction factor by the MYPD2 proposals.

4.1.3 Existing re-opener rule/approach

The MYPD1 rules provide for re-opening of the determination where the value of the correction factor exceeds specified threshold levels, as follows:

NERSA will ask for explanations from Eskom if the correction factor exceeds 3% of revenues, and at that point NERSA has the option of re-opening the determination.

If the balance exceeds 10% of revenues, then the determination would be re-opened as a matter of course.

In the MYPD1 rules these figures apply to Eskom Distribution revenues. In the final MYPD1 determination of February 2006, it was concluded by the Regulator that: “The most likely cause of any major balance in the correction factor is a sudden and substantial change in inflation expectations shortly after tariffs have been set.”.

8 The base allowed revenue is defined as the allowed revenue that is determined up front based on Eskom’s

price increase application.



Therefore it determined that the following condition shall apply, as a re-opener trigger:

If CPIX rises, or is expected to rise, at any time by more than 7% per annum, then the NER and Eskom will discuss the implications on revenues and costs, and the NER shall reserve the right to re-open the determination.

4.2 Correction factor as re-opener trigger

The MYPD mechanism determines Eskom‟s allowed revenue by adjusting the base allowed revenue for volume and inflation variance adjustments; pass- through variance adjustments; and incentive adjustments. If sales volume estimates are appropriate, the actual revenue derived from tariffs should match the base allowed revenue. The correction factor9 reflects the difference between the adjusted allowed revenue and the actual revenue. It follows from the generalised MYPD mechanism10 that the correction factor (CF) would be equal to the sum of the adjustments to the base allowed revenue. This is illustrated in the table below.

Rmillion Acronym

Return 14,000 ROR x RAB

Primary energy 30,000

OPEX Operating expenditures 14,200

Depreciation 5,600

Base allowed revenues 63,800 BAR = OPEX + ROR x RAB

Volume variance and inflation adjustment 0 VA

PE pass-through adjustment 6,000 PA

Incentive Adjustments 0 IA

Adjusted allowed revenue 69,800 AAR = BAR+VA+PA+IA

Volume 210,000

Price 30.38

Revenue recovered 63,800 AR = Volume x Price

Correction factor 6,000 CF = AAR - AR

Table 3: Sample calculation of allowed revenue and correction factor

It can thus be concluded that if the actual revenue and the base allowed revenue is about the same:

The correction factor (CF) reflects the total variance from the base allowed revenue;

The CF will be large if any of the revenue adjustments are large;

9 The correction factor (CF) = Adjusted allowed revenue(AAR) minus actual revenue (AR)

10 Adjusted allowed revenue (AAR) = Base allowed revenue (BAR) plus variance adjustments

(VA) plus pass-through adjustments (PA) plus incentive adjustments (IA) plus correction factor (CF).



The CF will trigger a re-opener when the MYPD forecasts deviate substantially from actual.

The CF is insensitive to expenditure variances not provided for in the adjustment factors. Note that the primary energy cost variance in the MYPD1 was more than 10% of the allowed revenue, but did not trigger a re-opener because the variance was not covered by the adjustments in the mechanism.

The benefit of using the CF to trigger a re-opener is that the Energy Regulator will be alerted whenever the revenue adjustments exceeds a lower value (3% of revenue) and will be obliged to re-open the determination when an upper value (10% of revenue) is exceeded. Customers are thus not exposed to excessive price variances being automatically passed on to them.

4.3 Eskom’s proposed trigger mechanism

In the Eskom rule change application of 30 April 2007, Eskom raised the point that the MYPD1 correction factor primarily tracks revenue variance, and does not adequately address variance in costs. For this reason, Eskom believes that a more effective indicator can be developed in which to trigger a re-opener.

Eskom proposed that the re-opening rule be based on an „earnings band‟ as a trigger for the re-opener. The mechanism would only trigger a re-opener and does not necessarily mean that the full deviation in earnings (positive or negative) would be adjusted in subsequent revenue allowances. The quantum of any adjustments to the revenue allowance would be a matter for the Energy Regulator to determine in consultation with stakeholders under the re-opening of the MYPD. This would be a symmetric mechanism‟ – in that if Eskom obtains windfall gains, that too would trigger the re-opener to the benefit of customers.

Eskom further supported the principles that:

Striking a balance between incentives and risk is central to the specification of the re-opener mechanism.

If the trigger levels are set too closely together, then the incentive power of the other various MYPD mechanisms will be diminished. Alternatively, if they are set too widely apart, the mechanism will not provide adequate risk mitigation properties.

The mechanism needs to be designed to be compatible to the overall working of the MYPD.

4.4 Earnings band as re-opener trigger

A re-opener based on an earnings band is normally used when, despite best efforts of the Energy Regulator and those of the entity, there remains a risk that the entity will earn excessively high or low profits under any price control given



the level of uncertainty over current and future costs. These re-openers take the form of a provision that, where the actual rate of return earned by the entity (calculated in accordance with regulatory reporting requirements specified by the Energy Regulator) diverges from the estimated WACC outside a specified band, then the Energy Regulator will undertake an interim review of the price control. This interim review will not consist of a full review of the allowed costs of the entity. Instead, it will consist of a reassessment of forecast against actual changes in inputs costs and outputs and an adjustment to the price control such that, using actual outcomes and updated forecasts for these cost drivers, the entity is restored to a position where its allowed return falls within the specified band for the remaining duration of the price control.

To retain incentives in order for the entity to manage its costs, it will not be returned to an allowed return equal to its estimated WACC. Instead, the adjustment will return it to a level close to the upper or lower boundary of the band, typically within one percentage point.

Actual ROR

Interim review re-

opener

WACC + X%

WACC - X%

WACC

Time (months)

Rate

of r

etur

n (%

)

Figure 1: Earnings band description

The earnings band is the deviation of actual earnings expressed as percentage of the actual RAB from expected earnings expressed as percentage of the forecasted RAB.

If there is little variance between the actual and forecasted capital expenditure in the period, it can be shown that this deviation will be equal to the variance adjustments and pass-through adjustments of the MYPD mechanism11. This

11

Actual earnings (AE) = Actual Revenue (AR) – Actual Expenditure (OPEX) = (Base OPEX + RAB x ROR) – OPEX = RAB x ROR + (Base OPEX – OPEX) = Target earnings + Revenue adjustments = Target earnings + Correction factor



trigger would thus behave in a similar way as the correction factor trigger to signal that expenditure is deviating significantly from what was expected and that it impacts the return of the utility.

If the operating expenditure adjustments in the MYPD mechanism are sufficient to remove large variances in operating expenditure, the earnings will be as intended and the earnings-band will not trigger a re-opener. Using the earnings-band as the only trigger mechanism, large operating expenditure adjustments would not trigger a review and this could result in excessive price increases being automatically passed through.

On the other hand, if the operating expenditure adjustments in the MYPD mechanism are inadequate to correct for the deviation of actual operating expenditure from the base operating expenditure, the actual earnings could deviate substantially from the earnings used to determine the base allowed revenue. This would result in unintended profits or losses being made which could be reviewed if an earnings band re-opener is used. In such instances the correction factor could be small.

If there is a large variance between the actual and forecasted capital expenditure, the rate of return on the actual RAB (including the capital expenditure variance) could differ significantly from the target rate of return on the forecasted RAB. In this case a re-opener would be triggered if the deviation from the target rate of return exceeds the trigger band.

4.5 Conclusions on re-openers

4.5.1 Trigger behaviour

It is concluded that the following trigger behaviour will occur, as illustrated in Table 4:

When the base estimates of operating expenditure and sales volumes are accurate neither the CF trigger nor the earnings-band trigger will operate.

When poor estimates are made and the allowed revenue is sufficiently adjusted by the MYPD mechanism the correction factor trigger would signal a re-opener. The earnings band trigger will however not operate.

When poor estimates are made and the allowed revenue adjustments do not fully account for the variance in operating expenditure, the correction factor may remain small when there are large OPEX variances and may not be triggered. In this case the earnings band trigger will see that the targeted earnings are not achieved and would trigger a re-opener.

When capital expenditure estimates are poorly made and only corrected at the end of the MYPD term, the correction factor trigger will not operate, the earnings band trigger could operate because the actual earnings rate is expressed as a percentage of the actual RAB while the targeted



earnings rate is based on the regulatory asset base that is derived from Eskom‟s capital requirements estimate.

4.5.2 Re-openers

With adequate adjustment factors for operating cost variances, the correction factor will be an effective trigger for a re-opener, however, when there are large variances in capital expenditure which are not adjusted in the mechanism the correction factor will not be triggered while Eskom‟s rate of return could deviate far from the target rate of return. The earnings band re-opener would cover this risk.

Using the earnings band to trigger a re-opener there is a risk that what could be considered as excessive price increases could be automatically passed through without review. This could be avoided if both the correction factor and the earnings band are considered when deciding on a review or a re-opener.

Because the correction factor is the net outcome of corrections for volume and inflation adjustments, pass-through adjustments, and incentive adjustments, it is an effective trigger. Having one central re-opener trigger to be monitored would be preferable to building re-opener triggers into the adjustment mechanisms (E.g. pass-through mechanisms).

In order to test the trigger behaviour, the sensitivity of the correction factor (CF) and earnings band (EB) triggers were established for variation of the following variables from the values used for determining the base allowed revenue:

Primary energy cost adjustment of plus and minus 20%;

Operating expenditure adjustment of plus and minus 10%;

Capital expenditure variance of plus and minus R12 billion (20% of assumed average annual capital expenditure of R60 billion) ; and

A combination of these scenarios.

In the ten cases considered, the earnings band trigger only operates in case 1. In this case the correction factor would also trigger a re-opener.

As a variation on this test, the sensitivity of the triggers to very large capital variances was tested. With a 100% variance in capital expenditure, the behavior of the CF and EB triggers is not aligned in two instances (4 cases):

When the primary energy pass-through variance is large and the capital expenditure variance small, (cases 3 and 8), the CF re-opener is triggered, but the EB re-opener is not triggered, this is because the ROR is not affected due to the increased allowed revenue due to the PE pass-through.



When the capital expenditure has a large positive or negative variance (cases 4 and 10) while there is insignificant primary energy or operating expenditure variances, the EB re-opener is triggered, but not the CF re-opener, as would be expected.

Table 4: Options for re-opener - various scenarios


Stakeholders are asked to comment on the adequacy of using the Correction Factor (a re-opener trigger based on the revenue variance) if expenditure volatility are passed through to revenue.


Stakeholders are asked to comment on the adequacy of using the earnings band (a re-opener trigger based on the rate of return variance) if expenditure volatility is passed through to revenue but capital expenditure variances are not used to adjust the allowed revenue in the review period.


Stakeholders are asked to comment on the adequacy of using both the correction factor and an earnings band to review or re-open the determination.

Case Scenario PE var. OPEX var.

CAPEX var.(Rm)

ROR ROR var.

Adjusted revenue (Rm)

Correction factor variance

CF trigger at 3%

EB trigger at 1%

1

PE&OPEX& CAPEX 20.0% 10.0% 12000 6.8% -1.2% 71,097 9.2% Y Y

2 PE&CAPEX 20.0% 0.0% 12000 7.5% -0.5% 71,097 9.2% Y N

3 PE 20.0% 0.0% 7.9% 0.0% 71,097 9.2% Y N

4 CAPEX 0.0% 0.0% 12000 7.5% -0.5% 65,097 0.0% N N

5 OPEX 0.0% 10.0% 7.2% -0.7% 65,097 0.0% N N

6

PE&OPEX& (CAPEX) 20.0% 10.0% -12000 7.7% -0.3% 71,097 9.2% Y N

7

PE& (CAPEX) 20.0% -12000 8.5% 0.5% 71,097 9.2% Y N

8 (PE) -20.0% 7.9% 0.0% 59,097 -9.2% Y N

9 (OPEX) -10.0% 8.7% 0.7% 65,097 0.0% N N

10 (CAPEX) -12000 8.5% 0.5% 65,097 0.0% N N



If the correction factor is mainly driven by deviations in expenditure (pass- through elements), there could be a perverse incentive to overspend deliberately when it is close to the re-opener level to trigger a re-opener. It is important to note that just because a determination is being re-opened that does not necessarily mean that the company will be allowed to receive more revenue.

The perverse incentive to overspend associated with threshold levels can be avoided by having a single, more flexible re-opener that is based on a “material change in circumstances” approach. It, however, is less transparent in that it is not as clear that an event has triggered as it is that costs of the company has exceeded a numeric threshold.


Stakeholders are asked to comment on using a material change in circumstance trigger together with a correction factor (or operating expenditure variance) threshold.

The present 3-year control used in the MYPD is short in the context of best regulatory practices. It constrains the flexibility to manage the long term capital expansion programme. The shorter period, however protects Eskom against unforeseen cost escalation factors.


Stakeholders are asked to express views on the length of the control and whether a longer period could be considered for the Eskom network businesses (distribution and transmission) which operate in a more stable environment than generation.

4.5.3 Practicality of re-opening a determination

A high probability of re-opening go against the intent of a multi year price determination where the regulated entity is incentivised to perform better than the base performance used to establish the base allowed revenue and to retain efficiency benefits. The risk of re-opening introduces regulatory uncertainty to the regulated entity and price uncertainty to the electricity users.

Re-opening also introduces regulatory lag between the time that a re-opener is triggered until a decision is made in this regard. Due processes of the regulator could take up to 6 months to come to a decision.

The requirements to mitigate against the negative effects of a re-opener are:



Accurate forecasts;

Separate re-openers for each Eskom business (Generation, Transmission, Distribution)

An appropriate adjustment mechanisms for volume and cost driver variances (CPIX);

A small variance between base estimate and actual value of pass-through items;

Awareness of anticipated re-opening to allow an early start in the process. The potential adjustments and the trigger should be monitored on a monthly basis, based on performance against the determination and projections for the future.

4.5.4 Joint or separate Eskom business re-openers

In time there will be a need to set separate price controls for Eskom and the REDs. We therefore need to consider whether it is appropriate to have a re-opener based on the position in Eskom‟s ring fenced businesses jointly or separate re-openers operating in each ring fenced business. Our initial thinking is that it is appropriate to have separate re-openers for each ring fenced business of Eskom, but for them to be based on the same underlying principles. This would be to protect funders as much as Eskom and would address concerns expressed by stakeholders regarding the transparency of the correction factor.

In the Eskom price increase application for 2008/9, the major source of the revenue variance that was allowed to Eskom Distribution came from the Eskom Generation Division. The adjusted price increase should have only influenced the energy component of the wholesale electricity price (WEPS) and not the average distribution tariffs.

Separate general re-openers for each regulated entity of Eskom Holdings are preferred by the Energy Regulator because it enhances transparency and would result in more cost reflective tariffs being implemented. The administrative burden on NERSA will not change significantly, because the MYPD mechanism already treats the regulated businesses of Eskom as three separate entities.


Stakeholders are asked to comment on using separate general re-openers for each of Eskom’s business activities and the ring-fencing of the Eskom regulated businesses as well as what an opportune time would be for making such a change.



Another aspect that must be considered is how the Eskom businesses should be ring-fenced in the current environment where the single buyer function of Eskom is accountable for power purchases from non-Eskom generation sources. The single Buyer function forms part of the Eskom Transmission and System Operations Division.

A possible way of arranging the ringfencing for price control purposes are given in the table below:

Eskom Organisation NERSA Licence Price control

Eskom Generation Division

Eskom Generation Licence

No prices, cost recovery contract with single buyer.

Eskom single buyer

International trader - Power imports

Not yet licensed WEPS energy charges

Eskom Transmission and System Operations

Eskom Transmission License

WEPS Transmission charges

Eskom Distribution

Eskom Key Sales and Customer Services (KSACS)

Eskom Distribution Licence

Purchase energy at WEPS rates.

Retail tariff revenue control.

Non tariff revenue

Table 5: Ringfencing options for MYPD2 revenue controls

At present only the Eskom Distribution revenues are controlled by the MYPD re-opener. Eskom‟s internal revenue flow from the Distribution Division to the Transmission and Generation Divisions are not controlled. It is foreseen that in the future the wholesale electricity pricing system (WEPS) would have to be used to determine the power purchase cost of distributors and traders (Eskom Regions, REDs and KSACS) rather than the current method of passing through the cost of generation and transmission to the distribution revenue control.

Another future implication is that it would be necessary to separate the wholesale price determination from the retail price determination. Once wholesale prices have been determined, the distributors can plan their power purchases based on the WEPS rates.




Stakeholders are asked to comment on the ringfencing of Eskom’s businesses and using the WEPS tariff to determine the Distribution power purchase cost.

4.5.5 Recommendations

It is recommended that:

1. The correction factor be retained as a re-opener trigger with a review level of 3% of the base allowed revenue and a re-opening level of 10%.

2. An earnings band trigger be added to the mechanism with a review level of 1% of the targeted rate of return.

3. When either one of the two triggers operate, the determination will be reviewed without necessary re-opening the determination.

4. The re-opener triggers (projected correction factor and rate of return) must be determined monthly based on Eskom‟s projections for the year;

5. The potential impact on price increases must be communicated to the public quarterly.

6. Eskom should report the re-opener triggers per ring-fenced business entity.

7. A price control framework should be developed for the Single Buyer function.

8. The WEPS rates should determine the power purchase cost of Eskom Distribution. This implies that the WEPS rates should be determined before the Distribution retail rates are determined.


Stakeholders are asked to comment on the overall recommendations for an appropriate re-opener within the MYPD2 mechanism.

5 Valuation of the regulatory asset base (RAB) While the valuation of the asset base did not form part of the Eskom application for rule changes and has also been consulted upon previously, NERSA felt it necessary to re-consult on the matter due to discussions held between Eskom and NERSA and on the new proposal by Eskom.

5.1 MYPD 1 approach

Opening assets for the first control period shall be the closing historic cost value of the assets as at the end of the financial year (31 March 2006) and a



real rate of return shall apply to them from that point forward. At the end of the control period, the opening assets and new investments after deduction of depreciation for the period shall be indexed using an inflation rate to form an opening valuation of the assets for the following control period.

5.2 Eskom’s proposed regulatory asset base valuation method

5.2.1. Initial valuation of the RAB for MYPD 2

Eskom‟s initial RAB for MYPD 2 will be (re)valued on the basis of its replacement costs, adjusted for the remaining life of assets (i.e. depreciated replacement cost).

Replacement cost will be calculated based on modern equivalent asset (MEA) valuation method.

The revalued RAB will be used in measurement of Eskom‟s revenue allowance under the MYPD on initial implementation.

Eskom will engage experts to undertake MEA valuation exercise and NERSA will be provided with all information pertaining to that study to enable it to fully scrutinize those findings.

5.2.2. Roll forward of the RAB

The initial RAB for MYPD 2 will be indexed up annually by CPIX from initial implementation in accordance with the current MYPD approach to indexing the asset base.

5.2.3. Periodic review

A process allowing for periodic review (proposed at every second MYPD) of the need for further MEA valuations would be applied, with the RAB (at its initial MEA valuation) indexed to CPIX otherwise. 5.2.4. Transitionary mechanisms Once the MEA valuation study is completed and the effect on the measurement of the revenues is able to be quantified, appropriate transitionary mechanisms will be applied.

5.3 Alternative methods for measuring the RAB

Regulatory asset base valuation methods can be categorized into cost-based or value based. The cost-based methodologies include historic cost, indexed historic cost, replacement cost and depreciated optimized replacement cost. The value-based methodologies include fair market value, net present value,



deprival value and optimized deprival value. These methods have distinct advantages and disadvantages, they involve varying degrees of effort to calculate, and they offer significantly different estimates of the RAB give different incentives, differs in their pricing and investment signals. The selection of asset valuation method for use in regulatory decisions is based on the level of appropriateness for that regulated utility.

a) Observations on the historic cost method

This method values the RAB on the basis of the original cost of the assets (setup and financing costs) and that value does not evolve over time. It is adjusted for accumulated depreciation in order to allow for the proportion of each asset‟s economic life that has been used. This is the simplest and least costly methodology to implement and it is widely accepted within the commercial sector as the preferred method for financial accounting. The main data requirements for this method include the actual capital expenditure, disposal of assets, depreciation and book values which are readily available in company‟s annual financial statements. The advantages of historical cost valuation are that, it is objective because its values are similar to those contained in the utility‟s audited financial records, it requires no subjective assessment of the value of the asset and is therefore immune to disagreements between the regulator and the regulated entity, it is transparent and predictable, and it complies with the standard accounting conventions. The main disadvantage of this method is that, it does not allow for revaluation of the asset base over time to take into consideration the impact of inflation and/or technological advances. Because of this, it tends to significantly underestimate the values of large assets with considerable service lives, and lead to underestimation of depreciation. It could also overestimate the value if major technological advances occur making current assets unproductive.

b) Observations on the indexed historic cost method

Indexed historic cost method is a modified historic cost approach for valuing the RAB. It adjusts the asset value upwards for inflation as measured by the consumer price index or some industry specific index. It shares the advantages and most disadvantages of the historic costs methodology but it doesn‟t underestimate the values and depreciation of large assets with considerable service lives to the extent that the historic cost does. It is consistent with regulatory regime that adjusts the RAB in line with inflation and allows real rate of return on the calculated RAB.

c) Observations on the replacement cost method

This method is also referred to as the modern equivalent asset value approach. It re-values the asset base to reflect its modern equivalent value



i.e. finding current market prices that one would pay now for an equivalent asset purchased in earlier years or treating old assets as new entrants. It values the RAB as the sum of the current costs of replacing each asset in the RAB with similar assets that replicate the capacity and service levels of existing assets. The estimates are then adjusted for depreciation. The advantages of current cost valuation are that, it matches the economic value when inflation is high and provides indication of capital costs to potential market entrants. Its drawbacks are that, it is subjective because current prices of an old asset may be difficult to determine, it may not take into account technological change and, if it does, the methodology of compensating for technological change may be subjective and overstate the actual economic value.

d) Observations on the depreciated optimised replacement cost

This method values the RAB on the basis of the replacement cost of “optimised” assets i.e. those that efficiently reproduce the capacity and service levels of the existing assets. The optimisation is designed to remove any inefficiency that existed in the RAB current asset configuration such as duplication, excess capacity and redundant assets. As with other method it applies depreciation on the assets. This method requires a certain degree of subjective judgement about the optimum configuration of assets in the RAB, and about the processes of optimisation that are embodied in the derivation of the valuations.

5.4 Views on Eskom’s proposal and other valuation methods

As can be seen, each of the discussed methodologies has different advantages and disadvantages. No asset evaluation methodology is superior to the other, regulators across the globe use different methodologies and the appropriateness of each methodology is a function of the unique circumstances in each country. In South Africa, these circumstances include, amongst others:

a. the restructuring of the electricity generation and distribution industries and the level of uncertainty around the timing;

b. government‟s inflation targets;

c. the need to send appropriate investment signals;

d. ensuring reasonable return on investment;

e. encouraging efficiency in operations and investment;

f. the need for market-players to earn appropriate returns.



This argument for upward valuation of Eskom‟s existing asset to match the costs of modern equivalent assets has been considered and we view such revaluation as double payment for the same investment i.e. the utility has already recovered a significant portion of the cost related to its old assets and it should not be paid again because it has already been paid. The real rate of return approach with no upward revaluation of the existing asset value has been used successfully in the UK electricity, gas and water industries, and in the Australian electricity industry. In the UK water industry this methodology was used to both manage price paths and to enable new investments in a sector with massive new investment needs. The Independent Pricing and Regulation Tribunal (IPART)12 supports the historical cost valuation by arguing that if regulation is to act as a surrogate for competition, its asset valuation methodology must be the same as that used by the private sector. Revaluing assets to MEV will substantially increase the asset base and the associated return on asset and we view this as providing alternative “free/generous” funding to Eskom over and above the available sources i.e. reserves, loans and shareholder‟s contribution or share capital. We are mindful of the fact that in the medium term (3 - 6 years) as the proportion of new assets to old assets increases, the average price is expected to increase. Prices will reflect the high cost of new investment as the value of most existing assets will be insignificant when compared to new build, that process must be natural and not be accelerated unnecessarily, and hence old, cheaper assets continue to be operational, the prices must be a weighted average of low-cost existing generation and high-cost new generation. It is correct that revaluing Eskom‟s assets will increase the return on asset but it is incorrect to suggest that moving prices upwards (unnaturally quickly) would send a correct price signal to decrease demand. Currently most demand is relatively price inelastic and so would not necessarily react in any significant way if prices rise due to the proposed revaluation. It is interesting to note that some of the most price sensitive loads have already secured long-term contracts with Eskom at prices believed to be lower than existing tariff levels. Thus, those loads that one might expect to be most likely to react to a marginal cost price would have no incentive to do so.

5.5 Proposed approach for asset valuation

The approach for setting the opening RAB for MYPD 1 was carefully considered, therefore it is considered unnecessary for NERSA to revisit such a fundamental part of the regulatory framework after only one review period.

12

Regulator of electricity prices in Australia



We propose that the indexing method be refined to allow for annual RAB indexing, the new approach to be implemented as follows: At the end of the year (not the control period), the opening assets and new investments after deduction of depreciation for the year (not period) shall be indexed using an inflation rate to form an opening value of the assets for the following year (not control period). This method allows for the annual revaluation of the asset base and immediate recovery of the associated returns on an annually indexed asset base whilst preventing the carry over of variances into the next control period. It maintains the economic value of Eskom‟s balance sheet even under extreme inflationary conditions.

Question to stakeholder # 22 Stakeholders are asked to comment on the choice of an appropriate asset valuation method taking into consideration the broad socio-economic imperatives of government and the specific needs of the electricity supply industry

Question for stakeholders # 23 Stakeholders are asked to comment on the appropriate rate of return methodology that will match their preferred asset valuation methodology.

Question for stakeholders # 24 Stakeholders are asked to comment on how MYPD 2 regulatory asset base should be rolled forward.

The Federal Energy Regulatory Commission (FERC - USA) indexes only the equity portion of the RAB. This ensures that the equity holder will not benefit from a write up of the RAB with respect to assets financed by debt. Only assets financed from equity are compensated by inflation. This scenario is applicable where ownership is generally private rather than public and where asset funding is from both equity and debt.

Question for Stakeholders # 25 Stakeholders are asked to comment on the part indexation (equity) of the RAB or the full indexation (equity and debt).

6 Consultation process

The intention of the consultation process is to have the sections that are consulted upon form part of the overall MYPD process. All other sections of the



MYPD mechanism were consulted upon in June 2006. The closing date for comments on this consultation paper will be 14 November 2008 followed by a stakeholder workshop on this consultation paper on 20 November 2008. After the workshop the paper will be revised and form part of the mechanism that will apply for the MYPD2 revenue controls.

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