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Review on
Electricity Tariff in Peninsular Malaysia
under the Incentive-based Regulation Mechanism
(FY2014-FY2017)
Suruhanjaya Tenaga
19th December 20131
OVERVIEW ON INCENTIVE-BASED REGULATION
CONCEPT AND IMPLEMENTATION
Suruhanjaya Tenaga is moving towards the Incentive-based regulation (IBR) in order to strengthen the following:
the economic regulatory framework for regulating TNB;the economic regulatory framework for regulating TNB;
the tariff setting mechanism and principles for tariff design;the tariff setting mechanism and principles for tariff design;
The move towards better regulation:
the tariff setting mechanism and principles for tariff design;the tariff setting mechanism and principles for tariff design;
incentive mechanisms to promote efficiency and service standards;incentive mechanisms to promote efficiency and service standards;
the process of tariff reviews; andthe process of tariff reviews; and
the creation of regulatory accounts and its annual review process.the creation of regulatory accounts and its annual review process.
11 Regulatory Implementation Guidelines were developed for the
implementation of IBR 3
What is incentive-based regulation (IBR)?
• A mechanism or methodology for the electricity tariffdetermination, focusing more efficiency gains and a structured process intariff evaluation
• An effective mechanism that being used globally, sometimes called asperformance-based regulation
• Only the efficient cost (CAPEX and OPEX) in electricity supply will be• Only the efficient cost (CAPEX and OPEX) in electricity supply will beaccounted in the tariff calculation
• Setting key performance indicators for the utility
• Introduction of incentives or penalties on the operational performance
• Efficiency gains will be shared between consumers and utility
4
How will an efficient utility benefit from IBR?
1500
2000
2500
3000
16
00
26
00
20
00 Allowable Opex
Actual
5
0
500
1000
1500
2012 2013 2014
12
00 16
00
12
00
15
00
20
00
Actual
If the utility manages to effect further savings:
• Total saving over 3 years – RM 700 million
• All the savings will accrue to the utility
How will these benefits be shared with consumers?
2500
3000
3500
4000
4500
5000
Without
Efficiency GainWith Efficiency
Gain
Next Regulatory Period Reset
OPEX (RM mill)
6
0
500
1000
1500
2000
2500
2012 2013 2014 2015 2016 2017
GainNew Reset
Benefit to
Consumer
• The efficiency carry-over allows utility to keep the benefit of gains for three years (before the next
regulatory period starts)
Incentive-based Regulation benefits in terms of service quality
Wide recognition that a trade-off exists between:
• The Service Quality and the Cost of Service
Generally higher service quality costs more; lower expenditure will over time lead to reduced service quality levels
7
Under incentive regulation, there is an incentive to maximize profit. Profits can be increased by reducing service quality.
Hence, the Regulator also has a societal obligation to regulate service quality to ensure:-
• Profits are not taken at expense of quality
• All customers receive a reasonable quality of service (not only those where it is profitable)
• Acceptable service levels are maintained
• Separation of TNB business entities’ accounts
• Determination of reasonable return to licensee (WACC of 7.5%)
• Imbalance cost pass-through mechanism for uncontrollable costs (changes in
forecast vs actual cost of generation)
Salient Components of IBR
• Setting of performance targets with incentive/penalty mechanism by regulator
• Efficiency sharing scheme between utility and consumers in the next tariff review
• Structured tariff determination and decision-making process
– Regulatory period from 2014 – 2017
– Establishment of regulatory accounts and reporting mechanism
8
TNB Business Entities under the Incentive-based
Regulation Mechanism (Accounting Separation)
Distribution & Retail Distribution / Customer
Services
Electricity Customers
(Connected to the Distribution System)
Average Electricity Tariff
Transmission Tariff
9
Generation
Transmission Transmission
Single Buyer Generation
Single Buyer Operation
Transmission Tariff
System Operations
TNB Generation IPPs
Single Buyer Tariff
(generation +
operations)
System Operation
Tariff
Base Tariff is set to reflect:
• the construction cost of transmission and distribution system;
• Base fuel and purchasing cost;
• Operation, maintenance and administration costs;
• with certain assumptions related to fuel prices, inflation rates (or CPI), exchange
Electricity Tariff Review = Base Tariff + Imbalance Cost Pass-Through (ICPT)
prices, inflation rates (or CPI), exchange rates.
ICPT:
• adjustment to reflect the change in uncontrollable costs from Base Tariff i.echange in fuel and purchasing cost
10
Revenue
Requirement
=OPEX Depreciation Tax
Return on Assets
WACC (Return)
x
Regulated asset
base (RAB)
+ + +
Will only form part of the
revenue requirement from
the 2nd Regulatory Term
+Efficiency
carryover
amount
Revenue Requirement Building Block Model Under
the IBR Framework
Return on Assets the 2 Regulatory Term
11
Efficiency • testing for efficiencies through benchmarking and trend analysis
• review of historical cost performance
• efficiency and prudency of asset management policies
• consistency with capex and sales forecast
Summary of Tariff Setting Framework under IBR
Single Buyer Generation Actual Cost Adjustment
• Generation Specific Cost
(Capacity Charge, Energy
Payment etc)
• Other Gen Specific cost
(Other PPA/SLA Charges
etc)
Single Buyer Operational
•Operation and maintenance
•Staff cost
•Depreciation
•Taxes
Transmission
•Operation and maintenance cost
•Depreciation
•Staff cost
•Taxes
System Operation
•Operation and maintenance
•Depreciation
•Staff cost
•Taxes
Customer Services
•Distribution operation and maintenance cost
•Depreciation
•Staff cost
•Taxes
Revenue Requirement = WACC x Regulated Asset Base Revenue Requirement = WACC x Regulated Asset Base
12
etc)• Renewable Energy Cost
(displaced cost)
•Taxes
Cost recovery
based on
Revenue Cap
Cost recovery
based on
Revenue Cap
Cost recovery
based on
Revenue Cap
Cost recovery
based on Price
Cap
Adjustment in the next regulatory period
• Incentive to be given or penalty to be imposed in the next
regulatory period
• Efficiency gains to be shared in the next regulatory periodgeneration costs
Cost recovery based on Actual
Cost:
• Fuel cost pass-through
• Adjustment of other specific
generation costs
Adjustment every 6 months
(imbalance cost pass
through)
Decision on Electricity Tariff Review
in Peninsular Malaysia
Tariff Components sen/kWh%
increase
Current Tariff 33.54
TNB Base Tariff 0.90 2.69
Fuel Components:
Average electricity tariff rate in Peninsular Malaysia to be increased by 4.99 sen/kWh (14.89%)
from 33.54 sen/kWh to 38.53 sen/kWh, from 1st January 2014, to cover:
18%↑ on
Return on
Ratebase
(Asset) and
OPEX
13
• Piped gas regulated price
(from RM13.70/MMBtu to RM15.20/MMBtu
@1,000 mmscfd)
0.51 1.52
• Coal (market price)
(from USD85/tonne to USD87.5/tonne
CIF@CV 5500kcal/kg)
0.17 0.51
• LNG RGT market price at RM41.68/MMBtu 3.41 10.17
NEW AVERAGE TARIFF 38.53 14.89
OPEX
82%↑ on
fuels
Average Fuel Price Trend In RM/mmBtu as of Sept 2013
LNG’s market
price plays a
major role in
the electricity
supply cost
LNG CIF Japan
MFO Price
LNG ex-Bintulu
40
50
60
70
RM/MMBtu
14
Gas Price to PGB
Applicable Coal Price (ACP)
Gas Price to GMSB
Gas Price to Power Sector
0
10
20
30
20
00
20
01
20
02
20
03
20
04
20
05
20
06
20
07
20
08
20
09
20
10
Jan
11
Fe
b 1
1
Ma
r11
Ap
r 1
1
Ma
y 1
1
Jun
e 1
1
July
11
Au
g 1
1
Se
p 1
1
Oct
11
No
v 1
1
De
c 1
1
Jan
12
Fe
b 1
2
Ma
r 1
2
Ap
r 1
2
Ma
y 1
2
Jun
e 1
2
July
12
Au
g 1
2
Se
p 1
2
Oct
12
No
v 1
2
De
c 1
2
Jan
13
Fe
b 1
3
Ma
c 1
3
Ap
r 1
3
Ma
y 1
3
Jun
e 1
3
July
13
Au
g 1
3
Se
p 1
3
~70%
subsidy
Cost Components in Electricity Tariff TNB FY 2013 (Historical)
Generation Cost
(75%)
• Capacity Payment (32%)
• Fuel Payment (68%)
Transmission Cost
(7%)
Distribution Cost
(18%)
40
Average Electricity Tariff (sen/kWh)
Average Electricity Selling Price FY 2013
(33.88 sen/kWh)
Fuel Price (gas and coal) is regulated by the Government in
current tariff setting
Capacity Payment is minimised via the competitive bidding
process15
10
15
20
25
30
35
40
Before
2006Jun-06 Jul-08
Mac -09 Jun-11Jan-14
23.526.32
32.531.31
33.54
38.53
Electricity Tariff Structure as of 1st January 2014
under Incentive-based Regulation (IBR) mechanism
Distribution /
Customer Services
Tariff
8.25 sen/kWh
Transmission
Tariff
3.66 sen/kWh
Single Buyer
Generation
Tariff
26.38 sen/kWh
System
Operation
Tariff
0.05 sen/kWh
TNB Generation
Service Level
Agreements
IPPs
Power Purchase
Agreements
Single Buyer
Operation
Tariff
0.19 sen/kWh
Average T & D losses is 8.5%
16
Average Electricity Tariff : 38.53 sen/kWh
Imbalance Cost Pass-Through
in every 6 months
(cost variation of forecast vs actual cost procuring electricity)
Fuel Cost : natural gas, coal, LNG and distillate
All costs incurred by the SB under the PPAs and SLAs ( incentive or bonus payments, liquidated damages, savings etc)
i.e.
Renewable energy displaced cost
Average Industrial
Tariff
36.15 sen/kWh
Average Domestic
Tariff
31.66 sen/kWh
Average Commercial
Tariff
47.92 sen/kWh
Average Overall
Tariff
38.53 sen/kWh
Subject to
Government
Approval
PERFORMANCE INCENTIVE SCHEME
Upper bound
cap
+0.5% of annual
revenue requirement
Revenue
incentive scale
0% of annual revenue
Actual performance
compared to target
• Incentive / penalty
capped at +/- 0.3% to
0.5% of annual revenue
requirement
INCENTIVE SCHEME
Upper bound
targetLower bound
target
Lower bound
cap -0.5% of annual
revenue requirement
Performance
indicator
scale
0% of annual revenue
requirementrequirement
• No incentive or penalty
if performance between
the upper and lower
bound targets
18
Business entities
Total Incentive
and
Penalty Cap
Example :
Amount of Incentive or
Penalty Cap Annually
Revenue
Requirement
Total Incentive
/(Penalty) Cap
RM RM
Example : Total incentive or penalty caps for TNB business entities
RM RM
Customer services /
Distribution±0.3% ARR 10,670,937,304 32,012,812
Transmission ±0.3% ARR 4,345,455,379 13,036,366
System Operator ±0.5% ARR 56,954,047 284,770
Single Buyer Operation ±0.5% ARR 336,151,090 1,680,755
Total 15,409,497,820.39 47,014,704
Note: Single Buyer operation ARR only refers to revenue required for operation of Single Buyer
*excluding power procurement costs of both IPPs (PPA) & TNB Plants (SLA) 19
Equivalent to 0.045 sen/kWh incentive or penaltyARR = aggregate revenue requirement
Code Performance Incentive Scheme Unit Weightage
(%)
Lower Bound
Target
Upper Bound
Target
Customer Services
CSPI1 System Average Interruption
Duration Index (SAIDI)
Mins./cust./year 50 70 55
CSPI2 Average of Minimum Service Level
Compliance Performance
% 25 84.11 94.11
CSPI3 Weighted Average Guaranteed
Service Level (3, 4 and5)
% 25 86.32 95.50
Transmission
TXPI1 System Minutes Minutes 40 5.1 1.5
TXPI2 System Availability % 30 99.04 99.48
TXPI3 Project Delivery Index Delayed month 30 5.47 0
System Operator System Operator
SOPI1 Wide Area Loss of Supply Event No. of wide area
system blackout
incident
25 1 0
SOPI2.1 Voltage Limit Compliance % 25 90 96
SOPI2.2 Frequency Limit Compliance % 25 90 96
SOPI3 Dispatch Adjustment % 25 0.4 0.2
Single Buyer
SBPI1 Dispatch Deviation % 25 0.4 0.2
SBPI2 Compliance to Timely Settlement of
Generators’ Invoices
% 25 99.55 99.85
SBPI3 Compliance to Malaysian Grid Code % 25 98.10 100
SBPI4 Compliance to Single Buyer Rules % 25 95.00 100 20
FAIR RATE OF RETURNFAIR RATE OF RETURN
AND
WEIGHTED AVERAGE COST OF
CAPITAL (WACC) DETERMINATION
Suruhanjaya Tenaga’s Approach
• In reaching the recommendation on whether TNB’s capex and opex forecasts are efficient and prudent, we:
– analyzed TNB’s revenue requirement proposal, tariff setting and other supporting information
– analyzed data and information provided by TNB during the review process
analyzed forecast of total capex and opex, in terms of:– analyzed forecast of total capex and opex, in terms of:• Meeting expected demand
• Complying with all applicable regulatory obligations and requirements
• Maintaining the quality, reliability and security of supply
– considered initial views expressed by KeTTHA
– conducted consultation sessions with TNB’s working level
– compared with data/information submitted under license conditions
– considered consistency of TNB’s proposal with government policies
22
Fair Rate of Return (ROR)
Fair ROR is a level of profit that utility is allowed to earn as determine by the Suruhanjaya
Tenaga based on the following consideration:-
� Maintain service to its customers;
� Maintain and expand the infrastructure to provide the services to customers. The
return should be able to attract capital from investors. Low return - insufficient
capital for growth - consumer unable to receive sufficient level of electricity service;
� Make a fair payment to capital providers i.e interest to bondholders and adequate
dividend to shareholders dividend to shareholders
� conforms to the return of similar investments.
� Promote efficient used of energy, prices should reflect marginal costs;
� Ensure the utility's long-term stability.
� Ensure fairness to all stakeholders. The utility could get capital to provide services
to consumer and at the same time the capital providers receiving fair profits on
their investment.
23
How Average Rate Base (ARB) is Determined
• The objective is to identify the amount of appropriate
capitals/assets and working capital that are prudently required
by the utility company in order to provide the regulated services.
• ST use Original or Historical approach to determine the value of
the Rate Base (RB).the Rate Base (RB).
• The figures is adjusted to exclude consumer contribution and
consumer deposit from RB
• The ARB is calculated by taking the average of the opening and
closing value of the rate base/assets
24
Determine the Fair Rate of Return
The fair Rate of Return is base on Weighted Average
Cost of Capital (WACC) which are determine using
Capital Assets Pricing Model (CAPM).
1. Risk free rate – Yield of MGS1. Risk free rate – Yield of MGSThe risk-free rate of return will be used as a floor of acceptable levels of
expected return from any given investment. Any equity investment should
exceed the risk-free rate of return. There is no reason for investor to take any
investment with inferior to Risk free rate.
2. Market premium to reflect the risk of the utility’s as
compare to the risk free rate.
25
WACC Parameters Actual market Parameters TNB's Proposal Recommendation
Stock TNB Beta 0.92[1] 1.435 1.435 [[4]
Market Return (Rm) 8.8%[2] 12.3% 8.8%
Risk free (Rf ) 4.0% 4.0% 4.0%
Market Risk Premium (Rm - Rf) 4.8% 8.3% 4.8%
Debt Margin (Dm) 2.19% 2.24% 2.24%
Tax Rate 25.0% 25.0% 25.0%
Regulatory WACC for TNB Under IBR (FY2014-2017) is 7.5%
Note:
[1] Based on beta for the period 2004-2012
[2] Rm - Market return of 10 yrs KLSE Index
[3] Average Gearing (2004-2011) is 39.5%
[4] Adjusted to reflect optimal gearing.
Weighted Cost of Capital Calculation
Actual market Parameters TNB's Proposal Recommendation
Capital Structure CostCapital
Structure
Weighted
CostCost
Capital
Structure
Weighted
CostCost
Capital
Structure
Weighted
Cost
Cost of Equity (Ke) 8.38% 60.5% 5.1% 15.91% 45.0% 7.16% 10.85% 45.0% 4.88%
Cost of Borrowing (Kb)[3] 6.18% 39.5% 1.8% 6.24% 55.0% 2.57% 6.24% 55.0% 2.57%
Weighted Cost of Capital 6.9% 9.7% 7.5%
26
IBR - REVIEW OF TNB’S PROJECTED
CAPEX AND OPEX
27
Review of TNB Capital Expenditure Proposal (RM Million)
9,978
18,601 1 108 339 29,027
15000
20000
25000
30000
35000
8,482
14,881 1 108 339 23,810
15000
20000
25000
30000
35000
Initial Proposal Recommendation
18%
28
9,978
0
5000
10000
Tra
nsm
issi
on
Dis
trib
uti
on
Sin
gle
Bu
yer
Op
era
tio
n
Sys
tem
Op
era
tio
n
Join
t C
ost
Tota
l
8,482
0
5000
10000
Tra
nsm
issi
on
Dis
trib
uti
on
Sin
gle
Bu
yer
Op
era
tio
n
Sys
tem
Op
era
tio
n
Join
t C
ost
Tota
l
Capital Expenditure 2014-2017 (RM Million)
3,000
4,000
5,000
6,000
15%
Transmission Capex Distribution Capex
3,000
4,000
5,000
6,000
20%
29
2,4
87
1,7
22
2,4
96
1,9
92
2,4
75
2,2
63
2,5
21
2,5
04
-
1,000
2,000
3,000
TNB's Initial Proposal Recommendation
2014 2015 2016 2017
4,8
70
3,4
56
4,5
53
3,5
77
4,5
73
3,8
13
4,6
05
4,0
35
-
1,000
2,000
3,000
TNB's Initial Proposal Recommendation
2014 2015 2016 2017
Average Rate Base (RM Million)
20,818 46
20,264 41,131
20,000
30,000
40,000
50,000
60,000
2014 2015
21,704 56
21,630 43,393
20,000
30,000
40,000
50,000
60,000
30
- 3
-
10,000
20,000
Sin
gle
Bu
yer
Sin
gle
Bu
yer
Op
era
tio
n
Tra
nsm
issi
on
Sya
tem
Op
era
tio
n
Dis
trib
uti
on
Tota
l
- 2
-
10,000
20,000
Sin
gle
Bu
yer
Sin
gle
Bu
yer
Op
era
tio
n
Tra
nsm
issi
on
Sya
tem
Op
era
tio
n
Dis
trib
uti
on
Tota
l
Average Rate Base (RM Million)
24,096 107
24,347 48,551
20,000
30,000
40,000
50,000
60,000
2017
22,802 69
22,983 45,856
20,000
30,000
40,000
50,000
60,000
2016
31
- 1
-
10,000
20,000
Sin
gle
Bu
yer
Sin
gle
Bu
yer
Op
era
tio
n
Tra
nsm
issi
on
Sya
tem
Op
era
tio
n
Dis
trib
uti
on
Tota
l
- 2
-
10,000
20,000
Sin
gle
Bu
yer
Sin
gle
Bu
yer
Op
era
tio
n
Tra
nsm
issi
on
Sya
tem
Op
era
tio
n
Dis
trib
uti
on
Tota
l
TNB’s Revenue Requirement 2014-2017 (RM Million)
116,273 849
16,189 201
36,541 170,054
80,000
100,000
120,000
140,000
160,000
180,000
200,000
32
-
20,000
40,000
60,000
Sin
gle
Bu
yer
Sin
gle
Bu
yer
Op
era
tio
n
Tra
nsm
issi
on
Sya
tem
Op
era
tio
n
Dis
trib
uti
on
Tota
l
Single Buyer Revenue Requirement (RM million)
17
,42
3
28
,64
9
17
,90
5
28
,89
7
17
,25
5
28
,56
4
10
,06
4
18
,48
4
30
,16
4
20,000
25,000
30,000
35,000
40,000
RM
Mil
lio
n
9,1
20
2,1
06
8,8
34
2,1
58
9,7
48
1,5
61
10
,06
4
1,6
15
-
5,000
10,000
15,000
Capacity Payment Variable cost and
fixed O&M
Fuel Cost Total
RM
Mil
lio
n
2014 2015 2016 2017
33
System Operation Requirement (RM million)
36
.1
40
.6
39
.6 45
.6
43
.6 5
2.7
48
.9
62
.5
30.0
40.0
50.0
60.0
70.0
RM
Mil
lio
n
34
3.4
1.0
-
4.2
1.8
-
5.2
2.8
1.1
8.0
5.6
-
-
10.0
20.0
30.0
Return on
Assets
Depreciation OPEX Regulatory Tax Total
RM
Mil
lio
n
2014 2015 2016 2017
Single Buyer Operation Requirement (RM million)
18
1.6
18
2.8
20
0.2
20
1.3
22
3.8
22
4.8
23
9.9
24
0.5
150.0
200.0
250.0
300.0
RM
Mil
lio
n
35
0.2
1.0
-0.2
0.9
-0.1
0.9
-0.1
0.5
0.0
-
50.0
100.0
150.0
Return on
Assets
Depreciation OPEX Regulatory Tax Total
RM
Mil
lio
n
2014 2015 2016 2017
Transmission Revenue Requirement (RM million)
1,5
61
3,7
25
1,6
28
4,0
10
71
0
4,1
17
1,8
07
4,3
37
3,000
4,000
5,000
RM
Mil
lio
n
1,5
61
96
7
82
1
37
5
1,6
28
1,0
21
85
5
50
5
1, 7
10
1,0
81
89
6
43
0
1,8
07
1,1
47
97
3
41
0
-
1,000
2,000
Return on
Assets
Depreciation OPEX Regulatory Tax Total
RM
Mil
lio
n
2014 2015 2016 2017
36
Distribution Revenue Requirement
4,4
48
8,1
07
4,6
88
8,8
96
4,8
68
9,3
92
5,3
57
10
,14
6
6,000
8,000
10,000
12,000
RM
Mil
lio
n
1,5
20
2,0
14
4,4
48
12
6
1,6
22
2,2
13
4,6
88
37
4 1
,72
4
2,3
96
4,8
68
40
4 1
,82
6
2,6
10
5,3
57
35
3
-
2,000
4,000
6,000
Return on
Assets
Depreciation OPEX Regulatory Tax Total
RM
Mil
lio
n
2014 2015 2016 2017
37
Conclusion : Average Tariff in sen/kWh
26.38 0.19 0.053.66
8.25 38.53
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
38
0.00
5.00
10.00
Sin
gle
Bu
yer
Ge
ne
rati
on
Sin
gle
Bu
yer
Op
era
tio
n
Sys
tem
Op
era
tio
n
Tra
nsm
issi
on
Dis
trib
uti
on
Ave
rag
e t
ari
ff
39
Thank�you�
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