1. National Energy Regulator of South Africa (NERSA)
Electricity Pricing
Presentation to the Parliamentary Portfolio Committee on Energy
National Energy Regulator of South Africa (NERSA)
8 September 2009

2. Presentation outline Electricity Price Regulation Background
Requirements of the Act
Rate of Return Methodology (ROR)
Multi Year Price Determination (MYPD)
MYPD Rule Change
Municipal tariffs
Eskom Retail Tariff Structural Adjustments (ERTSA)
Negotiated Pricing Agreements (NPA)
Protecting the Poor
Electricity Pricing Policy (EPP)
Conclusions

3. Electricity Price Regulation Background (1)
Regulation of electricity prices started after the National Electricity Regulator (NER) was established in 1995.
At the time of first licensing there were 379 electricity distributors, after the rationalisation of local government in 2000 the number was reduced to 177.
The initial efforts of the regulator were directed to rationalising tariff structures and achieving transparency and cost reflective pricing.
The following standards and guidelines were established by the NER:
Tariff structuring guidelines;
Cost of supply methodology;
Framework for negotiated pricing agreements;
Wholesale electricity pricing system (WEPS)
Initially Eskom’s price adjustments was regulated by pricing compacts
Customer compact to reduce the real price of electricity by 20% between 1992 and 1996;
RDP commitment to reduce the real price of electricity by 15% between 1994 and 2000.

4. Electricity Price Regulation Background (2)
The analysis of Eskom’s price increase application by the Regulator improved each year. The development of a uniform regulatory methodology for Eskom and Municipalities was initiated in 2001.
The Eskom price increase application for 2003 was unbundled for the first time into separate applications for their regulated businesses of generation, transmission and distribution.
In 2003 a framework for economic regulation based on the Rate of Return (ROR) Methodology was approved for application in the determination of the Eskom 2004 price increase.
In 2005 it was decided to move to a multi-year price determination (MYPD) for Eskom covering the period April 2006 to March The MYPD would allow price stability in the period of Eskom’s has to start providing for massive capital investments in new generation capacity.
In February 2006 the first MYPD price revue was decided on by the NER granting Eskom a price increase of CPI plus 1%.

5. Electricity Price Regulation Background (3)
The National Energy Regulator (NERSA) was established on 1 October Its predecessor, the National Electricity Regulator (NER) regulated the electricity industry from 1995 until 16 July 2006.
On 30 April 2007, after one year of operating under the MYPD1 control, Eskom applied for a rule change to reduce their revenue risk exposure.
On 20 December 2007, following wide consultation, the Regulator:
Declined the rule change for consideration in the second MYPD, but recognised Eskom’s capital financing needs;
Granted Eskom a 14.2% increase in 2008/9, translating into a 12% increase for municipalities.
From January 2008 to March 2008 Eskom engaged in extensive load shedding due to a national electricity supply shortage.
On 18 March 2008 Eskom applied for a revision of the 14.2% increase to 60% from 1 April 2008 based on changes in its business environment, increased primary energy costs and an accelerated DSM programme due to the power conservation programme (PCP).
On 18 June 2008, the Regulator approved a price increase of 13.3% in addition to the already approved 14.2% (27.5% overall increase for 2008/9).
The National Energy Regulator of South Africa (NERSA), decided at its meeting held today, Wednesday, 18 June 2008, to allow Eskom to recover additional primary energy costs of R2.827 billion through the electricity tariff. This approval amounts to a 13.3% average increase additional to the 14.2% already approved on 20 December 2007 resulting in a 27.5% average increase year on year.

6. Electricity Price Regulation Background (4)
Eskom failed to apply for the MYPD2 price control in September 2008 and continually postponed their submission date pending the resolution of a funding model with Government.
DOE published the South African Electricity Pricing Policy (EPP) in December 2008.
In January 2009 the MYPD2 rules were approved by the Energy Regulator following consultation and a public hearing.
On 5 May 2009 Eskom applied for a 34% price increase. The Regulator granted a 31.3% increase, including that Eskom absorb the 2c/kWh environmental levy imposed by the Minister of Finance from 1 July 2009.
Eskom has to submit their MYPD2 price increase application for April 2010 to March 2013 by end September to obtain the necessary approvals for implementation in March 2009.
Despite the large nominal increase in Eskom’s prices, in real terms it is still below the price level experienced during the generation expansion in the 1970’s.
Electricity price trend

7. Requirements of the Act
Section 15 of the Electricity Regulation Act, 2006 (Act no 40 of 2006 as amended) requires inter alia that:
“The regulation of revenues
Must allow an efficient licensee to recover the full cost of its licensed activities, including a reasonable margin or return;
Must provide for or prescribe incentives for continued improvement of technical and economic efficiency with which services are to be delivered.”
“Charges and tariffs
Must give end users proper information regarding the costs that their consumption imposes on the licensees business;
Must avoid undue discrimination between customer categories”;
May permit the cross-subsidy of tariffs to certain classes of customers.
Various regulatory methodologies are used to ensure that the allowed revenues, charges and tariffs complies with the requirement of the Act.

8. Rate of Return (ROR) Methodology
The ROR methodology is applied on an annual basis and does not provide incentives.
ROR was used for regulating Eskom up to 2005 and is currently being implemented for electricity distribution businesses of Metros.
Key requirements to implement the methodology are:
Ringfencing of assets and expenditure for the electricity business;
A starting value of the regulatory asset base.
The allowed revenue consists of the following components:
Allowed operating expenses based on rules;
Allowed assets based on rules – the Regulatory Asset Base (RAB)
Allowed return on the RAB based on the weighted average cost of capital (WACC)
Correction factor to claw-back or return over or under recovery of revenue.
Allowed revenue is the tariff revenue net of charges (E.g. connection charges) and non tariff pricing agreements.
Tariff revenue divided by the target budgeted sales volume gives the average price (c/kWh). The price increase is expressed as a % of the actual price in the previous determination.
ROR Formula
WACC Formula

9. Multi year price determination (MYPD)
The MYPD is applied to Eskom over a 3 year control period.
The multi year approach provides certainty of price increases in the control period and smoothes the price increase over the control period.
Each business (Generation, Transmission, Distribution) is regulated separately to manage the complex interrelationships;
The allowed revenue of Distribution determines Eskom’s retail tariffs;
The allowed revenue of each entity consists of the following components:
Cost of sales (input cost to the entity.)
Operating expenditure and Depreciation
Return on the Regulatory Asset Base (as for ROR)
Service incentives (Tx and Dx quality of supply. EEDSM allowance)
Ex post risk management adjustments (variances in sales volume, primary energy expenditure, capital expenditure, CPI)
Correction factor to claw-back or return over or under recovery of revenue.
Note: Allowed revenue does not cover capital recovery, but only depreciation and a return on the RAB (RAB includes capital work under construction)
The determination may be re-opened if certain control parameters are exceeded (balance in regulatory clearing account, target earnings).
Interrelationships
MYPD Formula

10. MYPD Rule Change (1)
The MYPD1 rules allowed ex post adjustments of allowed revenue for:
Variances in sales volume adjusted at the marginal cost of the most expensive Eskom coal-fired generation station (Majuba)
Variances in the number of electricity consumers being served;
Variances in CPI. Eskom’s nominal cost projections are deflated using a CPI estimate for each year of the control. The cost projections are If the actual CPIn estimated risk management
The MYPD1 re-opener trigger was based on the size of the correction factor (CF) with a 3% review level and 10% re-open level. The CF is largely dependent on the size of the adjustments to the allowed revenue, arising mainly from the CPI variance.
In MYPD1, the impact of under or over expenditure on capital was not provided for as a risk management adjustment in order to provide capital management incentives.
Eskom experience much larger increases in their primary energy cost in 2008 compared to their forecast in the MYPD1 submission. As these increases were unrelated to CPI increases or sales volume increases, the risk management adjustments was inadequate and a re-opener was not triggered.
Eskom’s rule change application of 30 April 2007 requested that:
Variances on primary energy cost be passed through to customers ;
Variances on the return and depreciation on capital be passed through to customers;
The trigger for re-opening the price determination be reviewed.
The rule changes applied for would allow Eskom

11. MYPD Rule Change (2)
Following consultation and a public hearing the Energy Regulator made adjustments to the MYPD2 Methodology.
Pass through of certain variances was included in the risk adjustment mechanism:
Pass through of primary energy cost will be allowed subject to certain rules;
All risk management variances will be recorded in a Regulatory Clearing Account (RCA), including the correction factor.
RCA balances below 2% of allowed revenue is carried over to the next year, between 2% and 10% it is allowed as a pass-through in the next financial year. Withdrawals from balances greater than 10% will be decided by the Regulator following consultation.
Prudently incurred over or under expenditure on capital projects will be recorded in a capital expenditure carry over (CECA) account and a pass through allowed in the third year if the amount is material. At the end of the control period the RAB is adjusted upward or downward for variances.
In MYPD2 the RCA will serve as a control mechanism to trigger a review or re-opening of the determination to allow the Regulator to review the impact of large adjustments to allowed revenues on tariffs.
In addition, the determination will be re-opened when actual earnings exceed a band of WACC +/- 1%.

12. Benchmark price levels
Municipal Tariffs
Municipal electricity distributors are provided with a price increase guideline based largely on the Eskom price increase.
Municipalities that wish to deviate from the guideline need to fully motivate for such deviations.
The Guidelines includes the following aspects:
Guideline % price increase.
Target expenditure on maintaining electricity infrastructure (>5% Revenue)
Benchmark tariff levels are provided for municipal distributors grouped per RED for the following customer categories:
Domestic low (100kWh/m), Domestic high (800kWh/m)
Commercial / Commercial prepaid
Industrial
Municipalities submit applications for tariff increases and structural adjustment to the Regulator after municipal budgets have been approved
Challenges include:
Compliance with timelines for approvals by Council and Regulator
Failure to submit information on financial and operational performance to the Regulator
Failure to obtain approval from the Regulator (Illegal tariffs)
Benchmark price levels
Timeframes

13. Eskom Retail Tariff Structural Adjustments (ERTSA)
Tariffs are the means to recover the utility’s revenue;
Tariffs need to be structured in the combination of different charging parameters that will recover the revenue
The Act and the Electricity Pricing Policy of the DOE guides the structuring of tariffs
A 5 year tariff plan guide the design of Eskom’s standard retail tariff structures to comply with requirements
Key issues are:
Making tariffs more cost reflective
Unbundling tariff components
Structural changes to Eskom are approved by the Energy Regulator following consultation. Changes are implemented with Eskom’s price increases
Tariff Structures
Eskom Tariffs

14. Negotiated Pricing Agreements (NPAs)
NPAs are agreements with large industrial users entered into by Eskom during the period of excess generation capacity (1990 to 2000)
Basis for NPAs are:
Negotiated with new industries for which the electricity price is a key factor for establishing the industry in South Africa (smelters);
Available to all customers in that industry;
Negotiated at the highest price above the marginal cost of electricity such that sales to the industry reduces the fixed cost of Eskom which would be payable by tariff customers.
Duration as short as possible to meet the objectives of the various parties involved in the NPA. Duration should not exceed the period of surplus capacity
All NPAs with short contract periods have run out.
Current NPA consumption amounts to 7.5% of Eskom sales.
NPA Characteristics
Most of the NPAs are commodity price and foreign currency linked;
Some NPAs have floor and ceiling limits to price changes over the period of the contract. Prices adjusted to remain within the range;
Loads are interruptible to manage immediate (hours) generation capacity shortages.

15. Protecting the Poor (1)
Addressing affordability is a major issue during periods of high price increases
The following measures have been introduced to protect the poor:
Facilitating access to electricity through government subsidised electrification;
Free basic electricity (FBE) to the indigent. First 50kWh/m subsidised by Government.
Free connections provided to Eskom’s low consumption residential customers;
Lower price increases applied to low consumption domestic customers. (15% vs general increase of 31.3%)
Residential inclining block (RIB) tariffs being investigated by regulator.

16. Protecting the Poor (2)
Electricity Pricing policy: Qualifying customers shall be subsidised through the application of a life line tariff (single energy rate with no fixed charge and limited in capacity to 20 Amps with a nominal connection fee).
Further options that could be implemented include:
Increase the FBE volume;
Making low consumption domestic tariffs VAT free;
Energy efficient housing.
The principles of cost of supply and cross subsidies needs further debate for equitable tariff structures and tariff levels.
Tariff cost reflectivity
One part and two part tariffs
Eskom Residential Tariffs
Cross subsidies

17. Electricity Pricing Policy of DOE (1)
Approved December 2008, provides excellent guidance and is gradually being phased in by NERSA;
Consist of 60 policy statements confirming existing practices, removing uncertainties and introducing new requirements;
New requirements:
The regulator, after consultation with stakeholders, must adopt an asset valuation methodology that accurately reflects the replacement value of those assets. At present indexed depreciated historic asset values are used.
NERSA, after consulting with stakeholders, should develop and publish a multi year price path on an annual basis.
Aspects of renewable power trading and pricing.
DME must update the NPA pricing framework setting out the evaluation criteria. (Previously done by NERSA.) NERSA will approve and monitor NPAs in accordance with the framework.
Wholesale energy and transmission prices must be available on a fair and non-discriminatory basis to all qualifying wholesale electricity traders. (Wholesale traders not yet licensed)
The cost of service methodology used to derive tariffs must accompany applications to the regulator for changes to tariff structures. (More discretion to regulated entity)

18. Electricity Pricing Policy of DOE (2)
New Requirements (Continued)
The component of non-technical losses and bad debt which exceeds the approved standard must be considered unacceptable and be removed from the approved revenue base that would otherwise impact on the return of owners.
Domestic tariffs to become more cost-reflective, offering a suite of supply options with progressive capacity-differentiated tariffs and connection fees. (Note not volume differentiated as per inclining block rate)
Assets which are not financed by the distributor, but from other sources and handed to the utilities shall be excluded from COS studies.
NERSA shall develop and implement an effective system, which must include compensation to the customer, to ensure that quality customer services are provided by distributors.
Targets
Cost reflective tariffs to reflect unbundled cost components within 5 years (2014)

19. Conclusions
The pricing and tariff guidelines established by the NER and NERSA had a major influence on the South African Electricity Pricing Policy.
Electricity customers have enjoyed considerable savings as result of below inflation and lower than applied for price increases.
Provision of new generation capacity has changed the period of price increases below inflation.
The high price increases has a major impact on those who can least afford it: the poor, small businesses and rural communities.
Forecasting of Eskom’s revenue requirement has deteriorated due to declining generation reserve margins leaving less room for “error”.
Increased usage (load factor) of generation capacity without provision of an adequate fuel (mainly coal) supply infrastructure introduced fuel price uncertainty.
Managing Eskom’s cost risks by passing it through in the tariff creates price uncertainty to distributors and end users.
Delays in concluding Eskom’s funding model places strain on the governance processes and the timelines for budget approvals, adding to regulatory uncertainty.

20. National Energy Regulator South Africa (NERSA)
END OF PRESENTATION
National Energy Regulator
South Africa (NERSA)

21. Average Electricity Price Nominal and Real since 1950
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The red graph shows the average Eskom electricity sales price from 1950 to 2008/9. The blue (top) graph shows the sales price in real terms, after adjusting the sales price for inflation with 2009 as base year. It can be seen that in real terms the electricity price of today is still below the price levels in the period 1976 to 1987 when Eskom had their previous build programme. The prices reduced in real terms during the period that Eskom had excess generation capacity (1992 to 2005) and is now again increasing as the reserve margins are low and new plant generation plant has to be constructed.

22. Formula for ROR Methodology
R = E + (V-d+w) x r
Where
R = the required revenue of the regulated entity;
E = the operating expenditure
V = the value of the regulatory asset base
d = the accumulated depreciation on the regulatory asset base
W = the allowance for working capital held by the regulated entity
r = the calculated rate of return using the weighted average cost of capital (WACC)
The formula for the rate of return methodology states that:
The allowed Revenue (R) is derived from:
Operating expenditure of the utility (E) PLUS a return on assets – the second term.
The rate of return is a market related return derived from the weighted average cost of capital.
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23. Formula for weighted average cost of capital (WACC)
WACC = (Kd x G) (1- tc) + [Ke (1-G)]
Where
Kd = cost of debt (country risk free rate plus debt premium)
G = level of gearing (optimal capital structure: debt/ debt +equity)
tc=company tax rate
Ke= cost of equity (using capital asset pricing model)
Capital asset pricing model (CAPM)
Ke = CRf + Eb (MRp )
CRf = Country risk free rate
Eb = Equity Beta
MRp = Market risk premium
As indicated in the ROR formula the return on assets is derived using the WACC.
The WACC formula consists of two terms. Firstly the cost of debt and secondly the cost of equity. These cost are weighted in accordance with the capital structure of the entity.
The cost of equity is determined using a generally accepted model (The capital asset pricing model) to take into account the country’s financial standing and the company’s financial standing.
The beta coefficient aims to provide an indication of the specific riskiness of a company relative to the market. The coefficient has been used to predict the extent to which a company’s share price would tend to change in response to changes in the level of the overall market. A Beta of 1 would give a company an equity risk comparable to the market as a whole. A regulated monopoly would have a Beta lower than 1 due to the protected nature of its market.
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24. Eskom regulated businesses - interrelationship
Licensed entity
Cost of sales
Sales - Source of Revenue
Eskom Generation
Primary energy (Fuel and Water) purchases
Tx network service purchases
Electricity sales to Wholesale Trader
Wholesale Trader
(Currently regulated as part of Eskom generation)
Power purchases from Generation
Power purchases from IPPs
Power Imports
Purchases of demand participation
Electricity sales to Eskom distribution and KSACS (retailer)
Power exports
Transmission Network Service Provider and System Operator
Purchase of energy losses from Generation
Purchase of ancillary services from Generators
Sales of network services to generators, distributors and the international trader
Reliability services
Eskom Distribution and Retailer (KSACS)
Power purchases from Wholesale Trader
Power purchases from embedded generation
Sales to municipal electricity distributors.
Sales to electricity users.
Each regulated business of Eskom is licensed for a specific activity and its activities are financially ringfenced. The Regulator takes the internal purchases and sales of electricity and sales into account when analysing Eskom’s application.
The cost of sales, or purchase of “raw material” and the sales of each business unit are indicated in the table. From the table it can be seen that:
The Generator purchases a network service from Transmission and sells its electricity to the Wholesaler.
The Wholesaler purchases power from Eskom and non Eskom generators (both imports and IPPs) and sells the pooled power to the electricity distributors and retailers at a wholesale price. KSACS is such a retailer.
The Transmitter provides a network service to generators, distributors and traders and purchases the losses it incurs from Eskom Generation (or the Wholesaler).
The Distributors purchase power from the wholesaler and a network service from the Transmitter to supply end users or municipal distributors.
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25. Formula of the MYPD Methodology
Rn = En + (Vn-dn+wn) x r +In-1 + RAn-1 + CFn-1
Where
R = the required revenue of the regulated entity in year n (nominal);
E = the operating expenditure (cost to supply) in year n (inflation adjusted)
V = the value of the RAB in year n (indexed)
d = the accumulated depreciation on the RAB in year n (indexed)
W = the allowance for working capital held by the regulated entity in year n
r = the calculated rate of return using the weighted average cost of capital (WACC) (real)
I = the performance incentive adjustment (+ or -) for year (n-1) (escalated)
RA = the allowed risk mitigating adjustments for year (n-1) (escalated)
CF = the correction factor: Allowed Revenue minus Actual Revenue for year (n-1), escalated.
n = year number
The MYPD methodology is an extension of the ROR methodology. The first year of the MYPD is virtually the same as the ROR methodology, as the impact of the previous years in the control period is not present.
The formula is expressed in terms of the relevant year (n).
In year two, the allowed expenditure and return for that year is adjusted upward or downward with the performance achieved in the previous year (year n-1).
The adjustments provided for are:
The incentive scheme (I) which depend on the previous year’s performance
The risk mitigation adjustments (RA) which provides for inflation adjustments or pass through of variances which arose in the previous year, and
The correction factor to correct for over or under recovery of revenue in the previous year.
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26. Tariff Structures Tariff Components Tariff Name Fixed charge
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Tariff Components
Tariff Name
Fixed charge
[R/Cust/m]
Energy charge
[c/kWh]
Time-of-use
energy charge
Capacity
charge
[R/kVA]
One-part single energy rate tariff (Lifeline tariff)
Two-part tariff
Two-part time-of-use tariff
Three-part tariff
Three-part time-of-use
The Regulator’s tariff guidelines provides for five tariff types as shown in the table.
A one-part tariff consists only of an energy charge. Such a tariff is not deemed to be cost reflective, but is a function of what metering is available. As the one part tariff must recover fixed cost in the rate, it would have a higher energy charge than a two-part tariff. This tariff is applied with prepayment metering. With low usage such a tariff is considered to be a lifeline tariff.
A two part tariff consists of a fixed monthly charge or daily rate and an energy charge. This is a more cost reflective tariff. The tariff can be used on prepayment systems by collecting the fixed charge at the vending point.
The two part TOU tariff has an energy charge that varies depending on the time that it is consumed. This tariff gives usage (demand management) signals to customers such that off-peak energy would be used for appliances that are not required to operate in the day. The metering is expensive and it is mainly used for large power users. With new technology the prices are coming down and Eskom is piloting its application in residential areas. Residential load is the biggest contributor to peak/off peak load variations.
A three part tariff is the same as a two part tariff, but includes a capacity charge based on the maximum demand used in the month.
The three-part time-of-use tariff is a similar variation on the two part TOU tariff.

27. Eskom tariffs – average price levels
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28. Benchmark price levels (c/kWh)
Geographic Area
Domestic Low
Domestic High
Commercial
Commercial Prepaid
Industrial
RED 1
(Cape Town/ WC&NC)
44 – 48
45 – 49
RED 2
(Ekhuruleni/ FS&NC)
39 – 43
50 – 54
46 – 50
RED 3
(Nelson Mandela/EC)
43 – 47
47 – 51
RED 4 (Johannesburg/NW)
49 – 53
48 – 52
RED 5
(Ethekwini/KZN)
RED 6 (Tshwane/LP&MP)
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29. Municipal tariff approval process and timelines
MYPD
draft decision
Economic and other
data analysis
and forecasts
Draft municipal
Guideline for public consultation
process
Public hearings
on guideline
Final guideline
Municipal
budgeting
Process
Council approval
Public consultation
NERSA receives
applications from
municipalities
Application within guideline
And benchmarks? No
Yes
Tariffs approved
by REC
Presentations at
public hearings
Recommendations
by Electricity
Subcommittee
by Energy Regulator
LEGAL AND OTHER CONSIDERATIONS
MFMA
Municipal Structures Act
Prescribed public consultation process
Council approval of municipal budget
National Treasury
Budgeting guidelines for municipalities
September
December
March
Draft application in January whilst consulting
April & May
End June
End October = deadline for submission
Of Distribution information forms (D-forms)
Review of application includes
financial and technical analysis
Annual review of Eskom’s price and municipal guideline
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30. Indicative cost reflectivity of tariffs
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31. One part versus Two part tariff
Over recovery
One part tariff not cost reflective
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Y-axis = Consumer cost / Utility Revenue (Rands)
Two part tariff reflects cost of supply
Subsidy
X-axis = Consumer purchase / Utility sales (kWh per month)
Two part tariff subsidises one part tariff
One part tariff subsidises two part tariff
Breakeven at 400 kWh/m

32. Eskom’s residential tariffs
Variable rate (c/kWh) declines as consumption increases. With RIB tariffs the variable rate remains constant or inclines.
Fixed rate (R/day) zero at low consumption, increases as consumption increases. Constant with RIB tariffs.
Average price declines.
Note first step is the 20A subsidised tariff.
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33. Cost reflectivity and cross subsidies
A cost of supply methodology has been established to determine the cost of supply to the various customer categories (NRS 058).
It is assume that a cross subsidy exist where the revenue received from a customer category is below the cost of supply.
Note that the EPP does not define “cost reflectivity” or whether incremental or full costs should be used.
There are other views on this matter (Ref Baumol and Sidak) which gives discretion on how the common cost of supply is allocated and hence on the existence of a subsidy.
“A cross subsidy is present when the average incremental revenue contributed by a product is insufficient to cover its average incremental cost, but the firm nevertheless earns sufficient revenue from all its products to cover its cost of capital together with its other outlays”.
There is a large gap between the extremes of avoidable and stand-alone costs for any customer class. Economic theory generally leaves the allocation of the gap or common costs to equity considerations.
In distribution businesses a large proportion of the network costs relate to fixed or sunk costs and so is a major consideration in the setting of prices.
Usually the choice of an arbitrary rule for apportioning common costs profoundly affects the magnitudes of the individual full distribution cost (FDC) figures that emerge from the calculation. Not surprisingly, therefore, the selection made among the alternative rules has sparked bitter and protracted disputes
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