IEEJ:September 2001

Forecasting Electricity Rates in a Liberalized Retail Market

Junichi Ogasawara, Economist, Electric Power Group
Tatsuya Yamada, Researcher, Electric Power Group
1. Introduction
In Japan liberalization of the electric utility industry is often considered from the stanceof “lowering electricity rates.” However, given that the electric utility industry iscapital-intensive and that technology innovation capable of jolting the industry’s overall
efficiency is not yet available, changing the business environment, particularly the
introduction of competition may have, among other things, a harmful effect on cost returns.
Also liberalization incorporates negative factors of lower electricity rates as well. While“partial liberalization” which is currently in practice will be reviewed and discussed in around2003 concerning the scope of retail liberalization, the mode of competition, etc., the systems
that will be employed are still unclear. This is has led to an increase in the uncertainties
within the electric utilities’ business environment as well. What is worse, as symbolized byskyrocketing crude oil prices since the summer of 1999, primary energy prices are becoming
increasingly volatile.
The impacts on electricity rates under a changing businessenvironment, in such areas as competitive systems and primary energy prices are a matter ofgreat concern.
This study is designed to grasp what factors contribute to varying electricity rates inquantitative terms. We developed a model to calculate electricity rates, and then analyzed towhat extent electricity rates were affected by such factors as the degree of retail liberalization,
the size of scale of demand and crude oil spikes.1

2. General Description of the Model
2.1 Calculation targets
2.1.1 Forecast periods and targets
Electricity rates are forecast for FY2005 and FY2010, identical to the periods employedin the supply plan. Due to statistical restraints, FY1998 was taken as the latest year withactual records available. As for calculation targets, we picked out two companies, so that themodel we prepared would not represent characteristics of any specific firm. Working

1

It should be noted that this study, part of a consigned study project, was conducted in June 2000.

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IEEJ:September 2001

efficiency was taken into account as well.
2.1.2 General
Electricity rates are based on (1) cost principle, (2) fair return principle, and (3)equity-among-customers principle. The cost principle defines the cost as “that which isnecessarily incurred when providing customers with good services under the efficientmanagement of electric utility business”. This is interpreted as a non policy-based price rating,but a rating determined by objective standards without a corporate mind strategy. Electricity
rates have been calculated on this cost principle. However since March 21, 2000, when theretail market was partially freed, electricity rates applicable to special high voltage consumers
were deregulated and freely set which became the standard. Fair returns are defined as thoseenabling electric utilities to raise the necessary funds to achieve a sustained development andto keep their profitability at an adequate level in order to cover interest payments, dividends,
etc. They are calculated in cooperation with the cost, which provides the basis for the rating.
Equity among customers is a principle that prevents electric utilities from favoring or
disfavoring specific customers in their sales policy. This principle requires adequate cost
distribution by demand area, based on which objective rating is secured.
Fig. 2-1 shows the actual rating processes following the three principles above.

Fig.2-1

Outline of Actual Electricity Rating Processes
General cost

Assumed plans

To calculate costof rateSupply-demand plan

Business expenses
Personnel cost
Fuel cost
Maintenance cost
Depreciation cost
Taxes
Purchased
electricity price
OthersBusiness returns

Equipment plan

Financial plan

Business plan

Specific costs
Electricity
ratingTo distributecost by demandLighting services
demandFlat-rate residential lighting
Residential lighting

Low-tension power
services demand

Low-tension power
Midnight power

High-tension power
services demand

High-tension power
Commercial power

Demand in specified
size

Rates for deregulated sectors

To review rating
systems.

(No regulation)

Flat-rate schedule
Meter-rate system
Basic-rate system(Source) Electricity Rating Study Group, “Electricity Rates for Citizens,” Power News Co., December 1999

2

Rates forregulatedsectors

IEEJ:September 2001

The cost principle is further divided into “general cost” and “specific cost.” “Generalcost” is the balance after subtracting from the sum total of all costs incurred in electricity
supply from generation to distribution, under efficient management and business returns. In
addition to deducting profit and necessary costs for supplying freed sectors. For the
calculation of total expenditure, by preparing a model pursuant to general-cost-method
standards, we estimated the general cost from published data found in such forms as financial
statements and the Electric Utility Industry Handbooks. Because we applied this calculation
rule to the actual records period, the outcome was not in accordance with electric utilities’operating costs, etc. that can be found in their financial statements.
“Specific cost” is related to the third principle. To prevent disparity in demand area or
differences among electricity consumers, this specific cost principle provides that electricity
rates shall be set fairly and reasonably in accordance to the specific cost based on thestandards that adequately reflect supply voltage and load characteristics of electricity
consumption patterns.
Meanwhile, business returns, related to the second principle, are calculated by
employing a rate base system, which requires the returns to be computed by multiplying
invested values in business (real and effective assets) by a given rate of returns. We madeour calculations conforming to this requirement.
Fig. 2-2 illustrates an overall flow of our electricity rate calculations. Based on the
supply plan, we first assume various cases, then calculate the general cost for each target year
utilizing the “general cost calculation model”. Then, by comparing the outcomes with the“assumed rate revenues” (without rate revision) determined using a “rate revenues calculation
model”, we are able to calculate the “rate revision ratios.” From the rate revision ratios, wethen calculate the revised general unit cost after the rate revision.

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IEEJ:September 2001

Fig.2-2 Overall Flow

Supply plan

Equipment
investment plan

Supply and demandbalance

Crude oil priceSeceded demandPrimary energy importprices, CIF
G eneral cost calculation

model

Rate revenues calculation
model
Assumed rate
revenues

General cost

General unit cost by major
contract class (before revised)
Ratio of rate revision
General unit cost (afterrevised)

2.2 Assumptions and case establishment
2.2.1 Case establishment
Given the very hazy environment surrounding the electric utility industry, we preparedvarious cases before making calculations. In specific terms, we first set up two cases of“crude oil prices.” Then, we prepared a “supply plan-based case,” which was taken fromindividual utilities’ supply plans with the assumption that there was no retail liberalization.
In accordance with this we prepared two additional cases differing in the “scope of retailliberalization” and three further cases differing in the “size of seceded demand.” In all, we
prepared a total of 14 cases, 2 x (1+2 x 3).

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IEEJ:September 2001

Fig. 2-3

Cases Calculated in Our Forecast(1) Supply plan-based case

Crude-oil base case
Levelsof
secededdemandPartial liberalization
caseCompleteliberalization case

Crude-oil ceiling case×2(2) Low
introduction case(5) Low
introduction case(3) Medium
introduction case(6) Medium
introduction case(4) High
introduction case(7) High
introduction case

2.2.2 Crude oil prices
The CIF price of crude oil imports in December 1998 hit a record low of $9.30/bbl
since the oil shock of 1974, and crude oil prices have continued to flag in recent years. Morerecently however, a series of OPEC agreements on production cuts from March 1998 havetightened the supply and demand, which has triggered a sharp upturn in the crude oil pricestarting in March 1999. As of February 2000, CIF import prices averaged $26.97/bbl, which
neared the levels during the second oil shock. Thus, crude oil prices have become extremely
volatile in recent years. Accordingly, we prepared two cases concerning crude oil prices.
One being the base case, where the crude oil price is assumed to have returned to an adequatelevel ($22/bbl). The other being the high price case, where the present high price is assumed
to continue in the foreseeable future ($30/bbl).
2.2.3 Supply plan-based case
Based on the electric utilities’ data concerning electricity sales amounts, equipment
investment plans and so forth which are all contained in the “FY2000 Electricity Supply Plan”
and “Management (Efficiency) Improvement Program” published in March 2000, we
calculated electricity rates, which were organized as the “supply plan-based case.” Because

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IEEJ:September 2001

the utilities’ supply plans assumed no seceded demand, the supply plan-based case assumes
no demand detachment either. As derivatives from this case, we calculated various scenariosof demand secession, which are described below.
2.2.4 Scope of retail liberalization
The current system is subject to a review in three years time, with “expansion of thescope of partial liberalization,” “complete liberalization” and “rights and wrongs of thecreation of pool markets” which have been cited as the three major issues to be discussed.
However, the extent of development of future institutional reforms remains unclear for thepresent. Therefore, in regard to the scope of liberalization of the retail sector, we haveassumed two cases. The first being the partial liberalization case, where partial liberalizationof the retailing area, currently limited to high volume demand (defined as receiving electricity
through transmission lines of 20,000 V or more and having peak power demand of 2,000
kW or more) is assumed to continue. The other is the complete liberalization case, where
the scope of retail liberalization is assumed to reach all customers, including residential
customers. Meanwhile, regardless of the degree of retail liberalization, we basicallyassumed that no institutional reforms would take place if they should involve electric utilities’organizational changes.
Table 2-1

General Descriptions of Customers by Voltage (10 utilities total)

Voltage
Extra-hightensionOver 20kVHigh tension 6kV

Low tension 100/200V

Demand size Commercial

Industrial

Total

RemarksOver
2,000kW

Some 2,200
contracts

Some 6,100
contracts

Some 8,300
contracts

26.3 TWh185.6 TWh211.9 TWh

Large-sizedbuildings, plants,
etc.

50kW~
2,000kW

Some
Some 410,000
290,000
contracts
contracts

Some
700,000
contracts

148.7 TWh288.2 TWh

Under 50kW

139.5 TWh

Small- andmedium-sizedbuildings, plants,
etc.

Residential,
Some 73 million contracts
retail shops
283.3 TWh
Some 77 million contracts

Total

799.0 TWh
(100%)(Note) The numbers of contracts are as of late March 1998. Electric energy is as of FY1998.
In parenthesis are the shares with total electric energy taken as 100%.

6IEEJ:September 2001

2.2.5 Degree of seceded demand
We assumed the size of demand secession resulting from retail liberalization based on
U.S. data was able to reveal how many customers in California changed their suppliers.
California attracted keen attention across the world for its drastic reforms of the electric
power market in 1998. We referred to California because the state completely freed retailingand published actual records of supplier changes by customer area. California’s actual
records are summarized in Table 2-2. In reference to the U.S. data, we determined the
maximum rate of secession, and then prepared three cases of high, medium and low
introduction cases.
Table 2-2 Actual Records of Supplier Changes in California (As of Late April 2000)
Unit

Residential

Commercial

Commercial(Under 20kW) (20-500kW)
No. of customers whochanged(A)Total no. ofcustomers(B)Industrial

Total(20-500kW) (Over 500kW)

Contracts

164,636

38,195

13,981

1,009

4,727

222,548

Contracts

8,829,384

981,108

195,410

5,228

113,462

10,124,592

1.90%

3.90%

7.20%

19.30%

4.20%

2.2%

669,800

25,813,541

Ratio of change(A/B)%

Demand changed(C)MWh

1,275,706

747,013

7,277,693

15,843,329

Total demand(D)MWh56,380,993

14,222,592

50,261,097

45,832,601

2.30%

5.30%

14.50%

34.60%

Rate of change(C/D)

Agricultural%

6,769,254 173,466,537
9.90%

14.88%(Source)California Public Utility Commission

Table 2-3

Rates of Demand Change in Our Forecast
Partial liberalization

California’s contract category

Lighting service

Residential

Complete liberalization

Low
introduction

MediumintroductionHigh
introduction

Low
introduction

MediumintroductionHigh
introduction

-

-

-

1%

2%

3%

Commercial(high tension)

Commercial(20 - 500kW)

-

-

-

5%

10%

15%

Commercial(extra-high tension)

Industrial(Over 500kW)

10%

20%

30%

10%

20%

30%

Low tension

Commercial(Under 20kW)

-

-

-

2%

4%

6%

High tension A

Commercial(20 - 500kW)

-

-

-

5%

10%

15%

High tension B

Industrial(Over 500kW)

-

-

-

10%

20%

30%

Extra-high tension

Industrial(Over 500kW)

10%

20%

30%

10%

20%

30%

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IEEJ:September 2001

2.3 Major assumptions
In preparing these cases, we set major economic variables as shown in Table 2-4.
GDP, the national bond yield and the exchange rate were assumed to be common to all cases.
The macro economic outlook employed the values forecasted by the Japan Economic
Research Center in its “Restart of the Japanese Economy II – Impact of IT Innovation and Its
Assessment.” While the Center estimated sections of FY2005 and FY2015, we came up
with the theoretical estimates for FY2010 by correcting the Center’s figures by the growthrate for a given period.
Table 2-4
UnitGDP

1 billion yen in 1990 price

Major Assumptions
1990

1998

2005

2010

436,044 480,165 531,807 600,518

98/90

05/98

10/05

1.2%

1.5%

2.5%

National bond yield

%

6.8%

1.6%

2.6%

2.9% -16.5%

7.3%

1.8%

Exchange rateyen/$

141.52

128.25128.25128.25

-1.2%

0.0%

0.0%

$/bbl

23.34

12.81

22.00

22.00

-7.2%

8.0%

0.0%

Base case
Crude oil import price, CIF
LNG import price, CIF$/ton

202.39150.33201.18199.22

-3.6%

4.3%

-0.2%

Coal import price, CIF

$/ton

50.76

37.61

38.25

38.41

-3.7%

0.2%

0.1%

Residual oil priceyen/kl

25,027

17,18924,75024,750

-4.6%

5.3%

0.0%

Crude oil import price, CIF

$/bbl

23.34

12.81

30.00

30.00

-7.2%

12.9%

0.0%

LNG import price, CIF$/ton

202.39150.33254.83252.88

-3.6%

7.8%

-0.2%

High price case

Coal import price, CIF

$/ton

50.76

37.61

38.99

39.15

-3.7%

0.5%

0.1%

Residual oil priceyen/kl

25,027

17,18931,332

31,332

-4.6%

9.0%

0.0%

2.3.1 Crude oil prices
Dubai, the benchmark crude oil price index on the Tokyo Market, was once priced at arecord low of $9 per barrel in December 1998, and spiked to the $28 mark in March 2000 due
to OPEC’s cooperative production curtailments, etc., thus remaining highly volatile these last
few years. Hence, we put the crude oil price at $22/bbl for the standard case, and $30/bbl
for the high price case, while referring to the Reference Case of the DOE/EIA Outlook.

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IEEJ:September 2001

Table 2-4 Major Assumptions

Tokyo Market, Dubai

35.00
30.00

London Market, Brent

25.00

NY Market, WTI

20.00

NY Market, WTI

15.00
10.00

4
20

00

.0

1
00

.0

0
20

99

.1

7
19

99

.0

4
19

19

99

.0

1
19

99

.0

0
98

.1

7
19

19

98

.0

4
.0
98
19

19

98

.0

1

5.00

(Source) Energy Data and Modelling Center, IEEJ, “EDMC Energy Trend”

Fig. 2-5
$/bbl
40.0

Crude Oil Price Outlook

Crude oil price
IEEJ 98
DOE00 High
DOE00 Reference
DOE00 Low
Base caseHigh price case

35.0
30.0

Outlook

25.0
20.0
15.0
10.0
1980

1985

1990

1995

2000

2005

2010

(Source) DOE00 is from DOE/EIA, “ International Energy Outlook 2000 ” (March
2000), and IEEJ98 from IEEJ, “Japan’s Long-term Energy Supply and Demand Outlook
and Challenges” (December 1998).

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IEEJ:September 2001

2.3.2 CIF prices for other primary energy imports
The prices for LNG and coal were also estimated in relation to crude oil in both thebase and high price cases. However, with coal, we found that the prices were only
superficially connected to oil prices and instead rather heavily dependent on Australia’s
exchange rates. As a result, coal price rises remained modest even when crude oil pricesrose to their highest level.
Fig. 2-6

Changes in Primary Energy Import Prices, CIF$/bbl, $/ton
60.0
50.0

Crude oil (leftaxis)
Coal (left axis)

300

LNG (right axis)

250

1
.0
20

00

.0
19

99

.0
19

99

.0
19

98

.0
19

98

.0
97

.0
19

19

97

.0
19

96

.0
19

96

.0
19

95

.0
95
19

7

0
1

0.0
7

50

1

10.0

7

100

1

20.0

7

150

1

30.0

7

200

1

40.0

(Source) Ministry of Finance, “Monthly Statistical Report on Japanese Trades”

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IEEJ:September 2001

Fig. 2-7

Price Outlook for Primary Energy Imports, CIF – Crude Oil Base Case$/bbl, $/ton
80.0

350.0

outlook

70.0

300.0

Crude oil (left axis)
Coal (left axis)
LNG (right axis)

60.0

250.0

50.0
200.0
40.0
150.0
30.0
100.0

20.0
10.0

50.0

0.0

0.0
1980

1985

1990

1995

2000

2005

2010

(Source) Actual records from the Ministry of Finance, “ Monthly Statistical Report on
Japanese Trades.” Forecast by IEEJ.

Fig. 2-8

Price Outlook for Primary Energy Imports, CIF – Crude Oil Ceiling Case$/bbl,
80.0

Crude oil (left axis)
Coal (left axis)
LNG (right axis)

70.0

350.0

outlook

300.0

60.0

250.0

50.0
200.0
40.0
150.0
30.0
100.0

20.0
10.0

50.0

0.0

0.0
1980

1985

1990

1995

2000

2005

(Source) Actual records from the Ministry of Finance, “Monthly Statistical Report on
Japanese Trades.” Forecast by IEEJ.

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2010

IEEJ:September 2001

2.4 General cost calculation model
At this juncture we have employed a general cost method in calculating the costs
incurred in electric utilities. General cost consists of:General cost = personnel cost + fuel cost + maintenance cost + capital cost + Taxes +purchased power + other expenses – revenues from inter-company power sales+ business returns
In constructing the model, we estimated each of these cost items from published data,typically those in financial statements for FY1980 – 1998. The model is outlined in Fig. 2-9.
Meanwhile, we prepared the model according to the company, while using the same model inall cases. The criteria on how each cost item was calculated are described below.
Fig. 2-9

Flow of General Cost Calculation Model

Up/down in book
value

=

Up/down in bookvalue

Capacity plan=

Up/down inconstruction cost=

Up/down in cumulative
depreciation cost

Personnel cost

Supply-demand plan

Personnel
streamlining plan

Fuel cost
Maintenance costPrimary energy prices
Seceded electricity
consumption byliberalization

Depreciation cost
Taxes
Rate base
Other expenses
Sales price ofpurchased electricity

×
Rate of businessreturns

Interests, etc.

Other revenues
Wheeling-fee
revenues
Business returns

General cost

2.4.1 Personnel cost
First by subtracting severance benefits from total personnel cost, then dividing thebalance by the number of employees, we obtained per capita personnel cost. Personnel cost
was estimated in relation to per capita compensation of employees.

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IEEJ:September 2001

2.4.2 Fuel cost
Dividing the fuel consumption amount by generated power output of each type of fuel(oil, gas, coal and nuclear), each fuel’s consumption rate is established. The rates are assumed
to remain unchanged in the future. Future fuel consumption is estimated by multiplying therates by fuel-specific generated output stated in the supply and demand balance.
Subsequently, cost items are divided into different kinds of fuel. Each fuel cost isdivided by each consumption amount which is established as the unit fuel cost. Then this unit
fuel cost is calculated presumably in relation to CIF prices for each kind of fuel imports. By
multiplying the resultant unit fuel cost by fuel consumption each of the fuel costs can becalculated.
2.4.3 Maintenance costs
First, the repair costs are divided into a portion of fossil fuel, nuclear, hydro and othergenerating facilities and a segment of others (distribution and general administration sectors).
The repair costs involved in the generating capacities are calculated by multiplying installedcapacities by unit cost, while others involve multiplying the sum total of electricity sales
amount and seceded electricity demand by unit cost. As a result, the repair cost turns out tobe the same in all cases. Particularly in regard to the distribution sector, due to theassumption that without affected transmission/distribution capacities, electricity demand(electricity sales amount + seceded demand) within a service area proves to be the same in allcases.
2.4.4 Depreciation cost
Depreciation cost is calculated by multiplying average book values at the beginning ofa term and the end of a term by an average depreciation ratio.
Depreciation cost = average book values at a term’s beginning and end X average
depreciation ratio
Period’s end book value = Period’s beginning book value + incremental value (completed
portion) – declined value (scrapped portion) + increase/decrease inconstruction cost burdens
The period’s end book value is calculated by assuming an increase/decrease incapacities, respectively. The incremental value in book cost is calculated by adding up
specific large-scale projects out of the actual and planned equipment and facility investments,
and assumes the other depreciation costs are calculated together. The declined value in bookcost is calculated by assuming scrapped facilities combined into one category.

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IEEJ:September 2001

2.4.5 Taxes
Public charges represent the sum total of property taxes, miscellaneous taxes, power
development promotional taxes, business taxes, corporate taxes, and water concession charges.
Property taxes are estimated from book values. Miscellaneous and business taxes are
estimated from gross revenues (revenues from lighting/power services + delivery costs).
The power development promotional tax is estimated from electricity sales amounts. Water
concession charges are given as an exogenous variable. Meanwhile, the corporate tax
employed in cost calculation is a theoretical value calculated back from stock dividends,
which we employ in our calculation as well.
2.4.6 Electricity purchase and sales prices
This item covers electricity purchase and sales prices when traded among electricutilities under area-to-area sharing agreements, as well as electricity purchase and sales prices
applicable when electric utilities deal with wholesale power producers, wholesale power
suppliers and IPPs. These are calculated by multiplying the average unit purchase and sales
prices by electricity amounts purchased and sold, respectively. Meanwhile, the unit purchaseprice from IPPs is estimated from an average rate of decoupling between the ceiling priceposted by electric utilities when inviting bidders and the ceiling price unveiled by the MITI
after successful bidding has been completed.
2.4.7 Other expenses
This item consists of rent, outsourcing fees, waste disposal cost, reprocessing cost,
decommissioning cost, retirement cost, miscellaneous expenses and others.
Waste
disposal-related costs are estimated from generated output. The remainder is given
exogenously.
2.4.8 Other revenues
Other revenues represent the sum total of additional charges for arrears, electric-utility
miscellaneous earnings, and deposit interest. These are given exogenously. In the casewhere seceded demand is assumed to result from liberalization, wheeling-fee revenues arecalculated and included in this item. Wheeling-fee revenues are calculated by multiplying
wheeling fees by the amount of seceded demand. In the partial liberalization case, thewheeling fee is set at the standard unit charge published by individual utilities. In thecomplete liberalization case, wheeling fees applicable to low and high volume customers,
respectively, are calculated on top of the standard one. The wheeling fees applicable to low
and high volume customers are calculated by taking distribution and general administration
costs which are actually recorded as the standard fees.

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IEEJ:September 2001

2.4.9 Business returns
Business returns are calculated by multiplying the rate base by the rate of businessreturns2.
Rate base = electric utilities’ properties + assets under construction + nuclear fuels + specified
investments + working capital + deferred assets
Working capital is counted as equivalent to the basic concept of 1.5 months’ operating
cost plus a 1.5-month amount from annual payments for fuels and other stored goods. Here,the operating cost includes the fuel, personnel, repair and other costs, while not covering suchthings as the depreciation cost and public charges. Of these items, electric utilities’
properties and working capital are determined endogenously, and the remainder is given
exogenously.
We calculated the rate of business returns by assuming an average interest on
interest-bearing debts outstanding, by putting the interest rate on future borrowing at thenational bond yield, which is one of the major assumptions that has already described, and by
taking payments of existing debts into account. Declines in outstanding interest-bearing
debts, thanks to more efficient management were also interwoven.

2 The rate of business returns is calculated as follows:

Rate of business returns= Rate of returns to owned capital X 0.3 + Rate of returns of borrowed capital
Rate of returns of owned capital is calculated by setting the upper limit equivalent to the rate of returnsof owned capital actually recorded by all industries except general electric utilities, and the lower limit
to the actual yields of such public bonds as national and municipal bonds.

(When the rate of returnsof owned capital actually recorded by all industries except general electric utilities stands below theactual yield of public bonds, the rate of returns of owned capital is calculated based on the yields of the
public bonds.)
Rate of returns of borrowed capital is calculated depending on general electric utilities’ actual amountof interest-bearing debts by producing a weighted average of interest rates involved in actual records ofinterest-bearing debts thereof.
(Source)“Supply Agreement Rating Rules”

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IEEJ:September 2001

3. Forecast Results
3.1 General cost
To forecast electricity rates, we first calculated, as the benchmark, the general cost (costof rate) from specific data in the supply-demand plans, equipment investment plans, etc., allunder the “FY2000 Electricity Supply Plan” and the “Management Efficiency Improvement
Program” released March 2000 by electric utilities. Later, we calculated the impact of
opening the electricity market in the form of retail liberalization which would increase
seceded demand. That is, we forecast the impact of seceded demand on the cost ofelectricity supply by calculating its impact on the cost and revenues. The forecast results are
expressed in a two-target-utility average in exponential terms.
The forecast results of the supply plan-based case, or the benchmark, showed that thecost of rate would go down. It reflects shrinking capital cost due to a falling rate of businessreturns, on top of utilities’ curtailments in equipment investments and repair works, as well as
further increased management efficiency by personnel cuts, etc. (Figs. 3-1 & 3-2).
3.1.1 Partial liberalization cases
Based on the rates of secession assumed, we counted electricity sales amounts secededfrom the target demand (commercial power services, extra-high tension, extra-high tension
power services), then adjusted electricity supply amounts by halting or closing existing plants
and correcting utilization factors.
It appears the Electricity Supply Plan, the basis for our forecast, originally assumed
halts and closures of aging oil-fired power plants to some extent. Therefore, as a response
measure to demand secession due to partial liberalization (if any), we assumed halts andclosures of LNG-fired power plants as well.
Forecast results of specifically preconditioned cases of partial liberalization are
illustrated in Fig. 3-1. In general, the unit cost of electricity sold is found swelling in
proportion to increasing demand secession, because the burden of such fixed costs as therepair and depreciation costs would set to rise if electricity sales revenues fell due to larger
demand secession.
In order to illustrate the impact of rising crude oil prices, Fig. 3-1 presents not merely
the base case of crude oil price ($22/bbl), which is among our major assumptions, but the highprice case ($30/bbl) that is an incremental unit cost.

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IEEJ:September 2001

Fig. 3-1

Forecast Results with Current Rate Levels Taken as 100(Partial liberalization cases)

100
2.14

2.53

2.72

2.86

FY2010

90
100
80

96.78

96.03

95.42

94.86

Increment
to unit costof the

2.58

2.30
2.44
FY2010

2.08

93.42

93.95

94.67

95.17

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3-1-2 Complete liberalization cases
From the rates of secession assumed, we counted the electricity sales amounts secededfrom the target demand (commercial power services, extra-high tension, extra-high tension
power services). Complete liberalization leads to greater demand secession rather thanpartial liberalization. Therefore, we adjusted the amount of electricity supply by taking
additional measures to the halts and closures of existing plants and correction of utilization
factors. They included deferring commission of newly developed captive power sources andslashing the amount of purchased electricity by deferring commission of wide-area powersources developed by other electric utilities and wholesale power producers.
Forecast results of the specifically preconditioned complete liberalization cases areshown in Fig. 3-2. Overall, the unit cost of electricity sold proved to be higher than inpartial liberalization cases.
This is because the burden of such fixed costs such as the repair
and depreciation costs would further rise as electricity sales revenues plunged sharply. Alongwith this seceded demand swelling would nearly double the size of partial liberalization cases.

17

IEEJ:September 2001

Fig. 3-2

Forecast Results with Current Rate Levels Taken as 100( complete liberalization cases)

100
2.55

2.86
90

1.97

2.14
FY2005

100
95.56

94.86

97.08

96.06

80

2.39

2.58

Increment
to unit costof the crude
oil ceiling
case

1.94

1.67

94.98

96.31

FY2010
94.17

93.42

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3.2 Impacts of different assumptions and forecasting methods on rate levels
By conducting sensitivity analyses, this section considers the “rate of business returns”
and “unit purchase price of electricity from outside.” in order to learn to what extent ratelevels should vary when different assumptions and forecasting methods were employed fromthose taken in our forecast.
Also of note, the projected electricity rate levels, given in the preceding sections, should
be taken into account because they are heavily preconditioned to such points as the size of
seceded demand and the crude oil price.
Table 3-1

Impacts on Rate Levels When Crude Oil Cost Varies by $1/bbl
2005

2010

Impacts on supply cost (yen/kWh)

0.09

0.07

Impacts on ratio of rate revision (%)

0.50%

0.40%

(Source) Prepared by IEEJ from our forecast results.

3.2.1 Rate of business returns
Given the nature of public utility charges, big profits are taken through unfair earningsof monopolies at the expense of customers, while electric utilities must live on their mediocre
profits. In both of these cases, electric utilities lose out on doing sound business. Thus,
adequate business returns are imperative, which should be the principle of fair returns. As asystem to put this principle into effect, the rate base system is currently employed, under18

IEEJ:September 2001

which business returns are calculated by multiplying the value of real and effective electricutilities’ assets by an adequate rate of returns. The electricity rate cuts, in practice since
1996, have seen a reduction of electric utilities’ successful efforts in increasing their
management efficiency. The lower rate of business returns that reflects falling interests is
also contributing somewhat to this.
In the days ahead, the rate of business returns is expected to be on a moderate decline
unless interest rates should otherwise be abruptly raised to a considerable extent (Table 3-2).
This is because the electric utilities’ fund borrowing period (corporate-bond redemption term)
generally spans 5 – 10 years, and because the average interest on interest-bearing borrowing
is likely to fall judging from low interest rates in the last few years.
As a result, in our forecast, the falling rate of business return is taken as a contributing
factor in pushing electricity rates down. Yet some may argue that the rate of business returns
would become an element unrelated to calculating the cost rate, once the principle ofcompetition is fully introduced into the electricity market. This in turn would dissipate theconcept of the heavy burden of general cost (= necessary costs + business returns). And yet,for electric utilities saddled with a huge amount of interest-bearing debts outstanding, unlessthe debts are reduced considerably, interest itself should remain unchanged as an element
highly influential on interest payment, which forms part of the cost of rate (Table 3-3).
Table 3-2

1960
8.00%

Past Rates of Business Returns and Our Forecast

1988
revision
7.20%

1996
revision
5.25%

1998
revision
4.40%

2000
2005
2010
revision (forecast) (forecast)
3.80%
2.80%
2.80%

(Note) The 1998 revision put the rate of business returns for Kansai Electric Power at 3.7%.
(Source) “Theory and Practice of Electricity Supply Agreement” and others

Table 3-3

Impacts on Rate Levels When Business Returns Rate Varies 1%
2005

2010

Impacts on supply cost (yen/kWh)

0.39

0.36

Impacts on supply cost (yen/kWh)

2.20%

2.00%

(Source) Prepared by IEEJ from our forecast results.

3.2.2 Electricity purchase price from outside
There are two kinds of electricity purchase price. One is “area-to-area electricity
purchase price” payable for electricity received from other general electric utilities. The
other is “electricity purchase price from other producers” payable for electricity received from19

IEEJ:September 2001

wholesale power producers and wholesale power suppliers.
The “area-to-area electricity purchase price” is applied to electricity purchased under anelectricity sharing agreement signed among general electric utilities to secure reliable
electricity services. This agreement has been signed among the nine electric utilities andaims at supply-demand stabilization, wide-area power development, equipment investment
curtailments, fuel cost reductions, etc. It is available in various forms, such as nationwide
sharing and two-utility sharing.
The “electricity purchase price from other producers” has generally represented theprice for electricity purchased from such wholesale power producers as Electric Power
Development Co. and Japan Atomic Power Co., as well as wholesale Electric Utilities likejoint-Ventured Power Utilities and Municipal Electric Utilities. Now that a bidding system
has been introduced, electricity purchases from IPPs are covered as well, and a quantitative
growth of this type is likely to proceed.
To forecast the unit purchase price involves various elements are interwoven. First,
partial liberalization of the electricity retail market can be cited as a factor to send the unit
purchase price down. If newcomers become fully active on the retail market and thus
intensify price competition, electric utilities are likely to seek lower purchase conditions at
price negotiations with other utilities and wholesale producers. Larger electricity purchasesfrom IPPs whose unit prices are relatively low would contribute to reducing the electricity
purchase cost. On the other hand, electricity purchase plans from newly developed sources,
which generally involve high generating cost, and greater use of renewable energy sources
can be cited as the factors to cause the unit purchase price to rise. This is the area that can bedebated when designing specific systems of electricity liberalization.
As purchased electricity strongly carries the nature of negotiated transactions,forecasting the unit purchase price for electricity is very difficult. In our forecast, it iscalculated back from actual unit prices in recent years. Yet, now that purchased electricity is
expected to continue to grow in the future, it should be taken into account that differences in
estimated purchased prices can greatly affect the assumed cost of purchased electricity (Table
3-4).
Table 3-4

Impacts on Rate Levels When Electricity Purchase Price Varies ¥1/kWh2005
Impacts on supply cost (yen/kWh)
0.2
Impacts on rate revision ratio (%)
1.10%(Source) Prepared by IEEJ from our forecast results.

20

2010
0.22
1.20%