Incentive-Based-Regulation-IBR.pdf

Incentive Based Regulation (IBR)

Regulatory Economics Department 13th May 2016

1

Economic Regulation

2

Incentive Based Regulation (IBR)

3

Base Tariff - 1st January 2014

4

Imbalance Cost Pass-Through (ICPT)

5

Performance Indicators

1

Economic Regulation

2

Incentive Based Regulation (IBR)

3

Base Tariff - 1st January 2014

4

Imbalance Cost Pass-Through (ICPT)

5

Performance Indicators

Electricity supply chain

“multiform production is more costly than production by a monopoly” –  William J. Baum ol (1977)  (1977)   A Natural Natural Monopoly will typically have very high fixed costs meaning that is impractical to have more than one firm producing the goods.

What is Economic Regulation…

Aims to ensure.. Economic Regulation

•

Form of government intervention to address inefficiencies arising from monopolistic markets e.g. natural monopoly sectors of electricity transmission and distribution

•  A substitute for competition where competition is not possible

Customers of monopoly are protected

Prices of Utility charges will be based on efficient costs

Quality of service and performance of the companies assets are maintained

Utility gets the right incentives to improve their performance and increase investments on an ongoing basis

Forms of Economic Regulation

Command and Control Regulation

1 2

Rate of Return regulation

4 3

Market Controls Regulation

Self Regulation

1. Command and Control Regulation

•

Imposition of standards backed up by legal sanctions if the standards are not met

•

Law is used to define and prohibit certain types of activity or force certain types of action

•

Standards can be set either through legislation, or by regulators empowered by regulation to define rules

Advantages

Disadvantages

•

Can be implemented quickly

•

•

Fixed performance standards backed up in law

Close relationship between regulator and business could lead to “regulatory capture”

•

Government or regulator to be acting decisively

•

Can be complex and legalistic.

•

Defining acceptable standards can be difficult

2. Rate of Return Regulation

•

Regulator constrain a firm’s monopoly pricing behavior by specifying the maximum rate of return

•

“Fair” approach to tariff determination – Regulators in Japan and in some US jurisdictions

•

If the actual revenue earned by the utility firm in the year is too low to meet the specified rate of return, the regulated price will be adjusted upward for the following year and vice versa

Advantages

Disadvantages

•

The utility firm still have a degree of autonomy in running its business to recover costs

•

•

Consumers will be protected from the overly high prices

Encouraging the regulated firm to over-capitalise by accumulating a rate base that is higher than the efficient level “Gold plating” (higher tariffs)

3. Self Regulation

•

It often takes the form of a business or a trade association developing its own rules of performance, which it also monitors and enforces

•

Some government oversight of the regulation, but as a rule self-regulation is often seen as a way of business taking pre-emptive to avoid government intervention

Advantages

Disadvantages

•

•

Could be self-serving/undemocratic

•

Legalism not necessarily avoided

•

Weak enforcement

•

Independent oversight difficult

Can be-well-informed, with a high level of commitment from firms

•

Cheap for government

•

Easy to change to fit circumstances

•

“Realistic” standards created

4. Market Controls Regulation

•

Market –based regulations can prove cost-effective, and minimize regulatory interference in the day-to-day operation of companies

•

Common market-based mechanisms such as: • Competition Laws; • Regulatory by Contract; • Tradable Permits; and • disclosure Regulation

Advantages •

Firms respond bureaucrats

Disadvantages to

market

•

 Applicable across sectors

•

Flexibility

•

Low enforcement cots

not

•

Uncertainties and transaction costs

•

Lack of response in crisis

•

Needs healthy permit market

•

Can create barriers to entry (disputes resolved by participants)

•

Depends a information

lot

in

reliability

of

1

Economic Regulation

2

Incentive Based Regulation (IBR)

3

Base Tariff - 1st January 2014

4

Imbalance Cost Pass-Through (ICPT)

5

Performance Indicators

The Energy Commission in 2012 developed the Regulatory Implementation Guidelines (RIGs) to establish the following…

Regulatory Implementation Guidelines

1

The economic regulatory framework for regulating TNB

2

Tariff setting framework and principles for tariff design

3

Incentive mechanisms to promote efficiency and service standards

4

Process of tariff reviews; and

5

The format of regulatory accounts and annual review process

RIGs  2012

Electricity tariff is regulated by the Government under the Incentive Based Regulation (IBR) framework

Regulated by

IBR is a framework to set electricity tariff Government

Customers •

Guidelines

Fair, affordable and transparent tariff

•

Ensure affordability to Rakyat

•

Efficient cost

•

Tariff which stimulates economic growth

•

Value for money for the excellent service in providing electricity

•

Ensure sustainability of the electricity supply industry

Source : Electricity Tariff RIGs, Suruhanjaya Tenaga, Jan 2012

TNB • Fair return on investment • Incentive to operate efficiently • Incentive for excellent performance

TNB is incentivised to increase efficiency in three broad areas…

Operational Efficiencies

Financial Efficiencies

Performance Efficiencies

- Rewarded for seeking efficiencies in operational & capital expenditure

- Rewarded for maintaining an efficient capital structure.

- Rewarded for delivering improvements in network performance.

IBR, also known as Performance Based Regulation has been widely adopted IBR is widely adopted in Europe…

… and being introduced in South East Asia

Performance Based Regulation

Performance Based Regulation

Cost-plus

No IBR Sweden Finland

Myanmar

Norway

Estonia Latvia Lithuania

Thailand

Laos

Denmark

Philippines

Ireland Netherlands

Vietnam

U.K. Germany*

Poland

Cambodia

Belgium Luxembourg

Czech R.

 Austria France

Malaysia Hungary Romania

Singapore

Slovenia

Monaco

Portugal 2

Brunei

Slovakia

Bulgaria

Italy

Indonesia

Spain

Malta2

Greece

• IBR is an improvement over the cost plus model as it enables tracking of efficiencies and costs • IBR applies to natural monopoly parts of the power sector such as transmission and distribution networks

IBR is a structured way to set electricity tariff

Electricity tariff reviews over the years After IBR

Before IBR sen/kWh

(+14.89%)

Announcement Date

24 May 2006

5 June 2008

12 Feb 2009

30 May 2011

2 Dec 2013

11 Feb 2015

Effective Date

1 June 2006

1 July 2008

1 Mar 2009

1 June 2011

1 Jan 2014

1 Mar 2015

Quantum

12%

24%

(3.7%)

7.1%

14.89%

-

Regulated Gas (RM/mmBTU)

6.40

14.31

10.70

13.70

15.20

15.20

Average Tariff (sen/kWh)

26.2

32.5

31.31

33.54

38.53

38.53

-

-

-

-

-

(2.25)

ICPT (sen/kWh)

Before IBR • • • •

Tariff setting was on ad-hoc basis No proper mechanism for tariff review Less transparent to customers Tag to gas pricing (Regulated since May 1997)

After IBR

ICPT

ICPT every 6 months

Base Tariff

Base tariff is reviewed once in every 3 years

Regulatory Implementation Guidelines (RIGs)(RIGs) Regulatory Implementation Guidelines

RIG

Description

1

Define business entity

2

Define the tariff setting framework

3

Revenue requirement principle

4

Establishment of WACC

5

Establishment of operating cost, capital cost, asset and consumption templates

6

Establish incentive framework for operational performance

7

Establish cost allocation principles

8

Establish fuel cost pass through mechanism

9

Establish tariff design principles

10

Establish Regulatory Accounts process

11

Establish process for establishing revenue requirement and tariffs

RIG 1 : Define Business Entity (1/2)

•

•

•

Under the IBR framework, Managed Market Model has replaced the traditional vertically integrated structure of Malaysian Electricity Supply Industry (MESI) Identified Five (5) business entities subjected to IBR mechanism: • TNB Generation (TNBG); • Single Buyer (SB); • Transmission; • System Operator (SO); and • Customer Services (CS)

Electricity Customers Electricity Tariff 

to be

The Independent Power Producers (IPPs) are collectively the sixth business entity in the Managed Market Model and contracts the sale of electricity with the Single Buyer SB and SO will be separated identified and ring fenced from other parts of the business

Funds

Customer Services

Generation Tariff 

Transmission Tariff 

Transmission

System Operations Tariff 

System Operations Single Buyer SLAs and merit order dispatch

TNB Generation

•

Flow of

PPAs and merit order dispatch

Independent Power Producer (IPPs)

Managed Market Model

RIG 1 : Define Business Entity (2/2)

The Managed Market Model incorporates 5 business entities Single Buyer (SB)

• Comprises the functions of the existing TNB’s Energy TNB’s Energy Procurement Division • SB procures electricity from IPPs and TNB Generation based on the terms of the PPAs entered into with the IPPs and Service Level Agreements Agreements (SLAs) entered into with TNB Generation • SB dispatches TNB’s generation TNB’s generation units and the IPPs based on a dispatch merit order • Dispatch merit order is based on the heat rate, fuel costs and variable operating costs

TNB Generation

• Includes the ownership, management and operation of generation plants owned by TNB • TNB Generation contracts with the Single Buyer for the sale of electricity based on SLAs

Transmission

• Includes the management, maintenance and development of the TNB transmission system for the transmission of electricity to end customers

System Operator (SO)

• Includes the current functions of transmission system operations of TNB

Customer Service (CS)

• Includes the management, maintenance and development of the distribution system and the sale of electricity to customers

RIG 2 : Define Tariff Setting Framework

•

•

There are 3 choices for setting the tariffs for the five (5) TNB BEs. The choices as per below: i. Revenue Cap ii. Price Cap iii. Actual Cost ST recommended a Regulatory Term of three (3) years (i.e. First Regulatory term 2015  –  – 2017)  2017)

Revenue Revenu e Cap What it is

• BEs operating under Revenue Cap regime are not exposed to forecast revenue due to differences between actual and forecast electricity sales, prices are adjusted to make up for the revenue difference

Price Cap • BEs operating under Revenue Cap regime are exposed to all revenue risk based on actual electricity sales varying from forecasts of electricity sales used to set price • The revenue for business entities will be based on actual electricity sales which may be diff erent to projected revenue based on initial forecasts electricity sales used to set price.

TNB Business Entities

Single Buyer Operations

Transmission System Operations

Customer Services

Actual Cost • TNB is allowed to recover all of its actual costs • Prices adjust to reflect changes in costs to ensure that the regulated entity does not earn less (or more) that the cost of providing services.

Single Buyer Generation

RIG 3 : Objectives and Focus Areas Areas of Revenue Requirement (1/6) Key Objectives

To establish estab lish the revenue requirement (RR) principles for each of the 5 regulated business entities (i.e. GS, Tx, CS, SB & SO)

To establish esta blish the incentive framework for the 5 regulated business entities

Definition & Focus Areas

Implementation Process

•

To forecast revenue rev enue which each eac h of the 5 business entities should recover from electricity customers (through electricity tariff)

ST / TNB may review the revenue requirement as follows; •Reviews are to be conducted every 3 years

•

The RR should enable the business entity; • to meet its operational, expenditure requirements, • to invest in new assets, • to pay relevant taxes, and • to deliver a market based efficient return to investors

•Submission needs to be provided 10 months prior to the next regulatory period (submission in Feb’17 for regulatory period Jan’18)

• Cost Incentives - to pursue efficiencies in OPEX & CAPEX • Financial Incentives -to pursue an efficient capital structure (debt and equity) • Network & Customer Services Performance Incentives - To incentivise improvements in network performance and customer service service (based on targets such as SAIDI, SAIFI, etc.)

RIG 3 : Annual Revenue Requirement Principles & Computation (2/6)

Annual Revenue Requirement *

Return on Regulatory Asset Base (RAB) @ WACC

Operating Costs

i

i

i

Efficiency Carryover Amounts

Tax Payments

Depreciation

i

i

i

i : denotes the regulated business entities

Item

Definition

Operating Costs

•

 Applies to only regulated activities / services

•

Include cost of services procured from related parties

•

For SB, the OPEX includes working capital (WC) requirements (Regulatory WACC multiplied by WC)

Return on Regulatory Asset Base (RAB)

 –

Calculated as forecast market return (Regulatory WACC) multiplied by the RAB

 –

RAB includes only fixed assets, used f or supplying electricity to customers excluding

Depreciation

•

 Annual depreciation forecasts of the assets are computed based on a straight line basis with reference to its estimated useful life

Tax Payments

• •

Based on the calculation of t axable income and the applicable tax rates Capital allowances are based on the applicable capital allowances rates as per the current and relevant Malaysia Tax Guide

Efficiency Carryover Amounts

•

Base Incentive – to retain variance between actual Opex and Capex relative to forecasts

•

Efficiency Carryover Scheme – to provide a continuous and sustained incentive to pursue efficiencies over Regulatory Term

•

Cash or financial assets;

•

Consumer contributions and customer deposits

* Calculation of Annual RR is done via Revenue Requirement (RR) Model

 Provided by Energy Commission

RIG 3 : Establish Revenue Requirement Principles (3/6)

Building block for establishing revenue required

Revenue Required

⁼

WACC

⁺

Operating Costs

⁺

Depreciation

⁺

Tax Payments

X Revenue requirement calculation over a (3 year) Regulatory Term

Regulated Asset Base (RAB)

Return on Assets

Will only form part of the revenue requirement from the 2nd Regulatory Term Applicable to: • Single buyer (Operations) • System Operations • Transmission • Customer Services

⁺

Efficiency Carryover

RIG 3 : Establish Revenue Requirement Principles (4/6)

Revenue Required

⁼

WACC

⁺

SB Generation Costs (Actual Costs)

⁺

Depreciation

⁺

Tax Payments

⁺

Efficiency Carryover

X Regulated Asset Base (RAB)

Return on Assets

Single Buyer (Generation) • Comprises the costs of electricity procurement (EP and CP) under the PPAs, and SLAs, as well as Interconnection Agreement

Applicable to Single Buyer (Generation)

RIG 3 : Establish Revenue Requirement Principles (5/6)

Return on Assets (ROA): The ROA component should deliver an efficient market based return to investors in the business entities (WACC X RAB)

WACC

The forecast market return is set as the nominal after tax weighted average cost of capital (WACC). Is discussed comprehensively in RIG 4.

X Regulated Asset Base (RAB)

Return on Assets

 Average of s t a r t i n g a s s e t v a l u e and closing asset value. S t a r t i n g a s s e t v a l u e : measure of company investment

• • • •

Once set, not changed, promotes certainty & lowers risk Includes only fixed assets such as plant and equipment Does not include other assets such as cash, financial assets, investment in subsidiaries, tax assets intangibles and goodwill. The starting asset values are net of upfront customer contributions or capital received from governments in the form of government grants or subsidies.

Closing asset value  :

• Starting asset value – annual depreciation + forecast capital expenditure

The Regulatory Asset Base (RAB) comprises the assets used to provide the regulated services (6/6)

New Investment

Construction work in progress

Existing Assets Capital Contribution

RAB

RIG 4 : Establishment Return Requirement (WACC) (1/2) •

WACC is the economic cost (return) associated with a firm's requirement for capital –i.e. suppliers of capital require a market return on capital provided

•

Under the IBR mechanism, TNB is allowed to earn a rate of return at least equal to the WACC

•

WACC will provide an efficient return to the regulated entities and deliver efficient prices to customers. ST will ensure WACC for the TNB BEs : • based on an efficient capital structure and credit rating • reflects market based returns on debt and equity • adequately reflects regulatory and market risk; and • there is consistency between all the WACC parameters and the underlying cash flows calculated in the determining the ARR for the relevant TNB BEs Breakdown of Parameters for WACC determination Market Risk Premium 4.8 %

Cost of Equity

x Equity Beta 1.435

Company Equity Risk Premium 6.89%

45% of Cost of Equity +

Cost of Equity 10.85%

Weighted Cost of Equity 4.88%

Risk Free Rate 4.0%

+ Risk Free Rate 4.0%

Cost of Debt

+ Debt Margin 2.24%

Levered Company Cost of Debt 6.24%

x (1- tax rate) Tax Rate 25%

x 0.45

Weighted Cost of Debt 2.57%

Net Cost of Debt 4.68%

WACC 7.5%

x 0.55

55% of Cost of Debt Note: TNB IBR Final Recommendation by ST (21st May 2013)

TNB’s rate of return approved by the Government under IBR is on par with other countries (2/2) Rate of return, Percent PRELIMINARY

11.30%

8.55%

8.67%

7.00%

7.15%

7.50%

7.50%

M  a l    a  y   s  i    a

B  r   a z  i   l  

7.90%

9.80%

7.13%

 G  e r  m  a n  y 

F  r   a n  c   e

Developed countries

I   r   e l    a n  d 

P  h  i   l   i    p  p i   n  e  s 

P   o l    a n  d 

 C  h  i   l    e

Emerging markets

H  u n  g  a r   y 

R  u  s   s  i    a

RIG 6 : Establish Incentive Framework for Operational Performance (1/2) Penalty / Incentive Scheme •

TNB is monitored by ST for its operational and customer service performance

•

Under this performance based scheme, TNB will be incentivised when BEs exceed the upper performance targets. In contrary, penalty will be imposed to TNB when the BEs fails to meet target

•

Incentive slope

For Trial and RP1 (2014-2017), no incentive or penalty amounts will be implemented

Penalty slope

RIG 6 : Establish Incentive Framework for Operational Performance (2/2) Business Customer Services

Transmission

System Operator 

CSPI1

SAIDI

Weightage (%) 50

CSPI2

Average of MSL Compliance Performance

25

CSPI3

Weighted Average GSL (3, 4 and 5)

25

TXPI1 TXPI2 TXPI3

System Minutes System Availability Project Delivery Index

100 40 30 30 100

SOPI1

Wide Area Loss of Supply Event

25

SOPI2.1

Security Limit Compliance: Voltage Limit Compliance (VLC)

25

SOPI2.2

Security Limit Compliance: Frequency Limit Compliance (FLC)

25

SOPI3

Dispatch Adjusment

SBP1

System Average Cost Compliance to Timely Settlement of Generators' Invoices

Code

SBPI2 Single Buyer 

SBPI3 SBPI4

Performance Indicator  

 

Percentage Compliance to Malaysian Grid Code (MGC) Percentage Compliance to single Buyer Rule (SBR)

25 100 25 25 25 25 100

Note: MSL: Minimum Service Level

RIG 7 : Establish cost allocation principles (to allocate common costs)

•

The costs that a regulated entity incurs in the provision of regulated services can be broadly categorised into either direct costs or joint costs Direct costs

Joint costs

•

Costs incurred for activities that are required solely for providing regulated services applicable for that specific regulated entity

•

Costs for activities performed centrally by the corporate group for more than one regulated entity (or a combination of regulated and non-regulated business entities)

•

Ring fenced from other activities of the corporate group and are recorded and captured directly in an account category which belongs solely to the relevant regulated entity

•

Centralisation of certain corporate functions such as corporate IT and Treasury is often the most efficient means of delivery

•

Joint costs related to regulated services have to be allocated to the relevant regulated business entities to enable regulated cost recovery from electricity customers via electricity tariffs

•

E.g., costs incurred for meter reading activities typically are direct costs for a regulated distribution business entity

RIG 8 : Establish Fuel Cost Pass Through Mechanism

•

•

•

Imbalance Cost Pass-Through mechanism established to enable the recovery of actual fuel related and other generation specific costs ICPT allows TNB to reflect changes (either increase or reduction) due to the fluctuations in fuel and generation costs in the electricity tariff every six (6) months, subject to Government’s  decision and approval. The key objective of ICPT is for TNB to be financially neutral  (i.e. not be adversely affected nor benefit) with respect to the fuel prices volatility and other uncontrollable costs.

Imbalance Cost Pass-Through (ICPT)

Fuel Cost Pass Through (FCPT)

 Adjustment in the following 6 month period

•

Formula: FCPT (gas and coal only)

Changes in gas and coal costs

Generation Specific Cost Adjustment (GSCPT)

 Adjustment in the following 6 month period

Formula: Actual revenue based on Generation Specific Cost = Actual cost of generation

Changes in: • Other fuel costs such as distillate and fuel oil •  All costs incurred by the SB under the PPAs and SLAs • Renewable energy displaced cost

Benefits of IBR implementation

Customer

Utility

Regulator/Government

•

Electricity tariff set at efficient cost of supply

•

Fair return set at cost of capital (WACC)

•

•

Transparency in the cost components which make up the overall tariff

•

Incentive mechanisms which allow utility to retain full/partial efficiency gains

Simulate a competitive environment for natural monopoly sectors

•

Efficiency gains shared with customers

•

ICPT mechanism to passthrough of uncontrollable costs

Transparency in cost components of the electricity value chain

•

Performance standards which commensurate with the tariff charged to consumers

•

Rewards for exceeding performance targets

Better allocation of subsidy (direct and indirect)

•

 Achieve optimal balance in meeting both customers’ and utility’s needs

•

•

1

Economic Regulation

2

Incentive Based Regulation (IBR)

3

Base Tariff - 1st January 2014

4

Imbalance Cost Pass-Through (ICPT)

5

Performance Indicators

The forecasted average tariff for each business entity is based on the Revenue Requirement model and will be applied and fixed over the Regulatory Term

Forecasted Total Annual Revenue Requirement

Total Average Electricity Tariff

Generation Specific Forecasted Revenue Requirement

Generation Specific Tariff

Single Buyer Operations Forecasted Revenue Requirement

Single Buyer Tariff

Transmission Forecasted Revenue Requirement

Transmission Tariff

System Operator

Customer Services

Forecasted Revenue Requirement

Forecasted Revenue Requirement

System Operator Tariff

Customer Services Tariff

IBR comprises of two key components for tariff setting: (1) Base Tariff and (2) Imbalance Cost Pass-Through (ICPT)

sen/kWh

+ ICPT ICP

+ICP ICPT - ICPT

- ICPT

ICPT

1

Base Fuel and Generation Cost

Base Tariff

Fixed Cost • • • 2014

Development Operation Maintenance

2015

2

2016

Trial and First Regulatory Period

2017

The benchmark fuel prices in Base Tariff effective 1 January 2014

Fuel Component

Domestic Piped Gas

Unit Price

RM15.20/mmBTU for gas volume ≤ 1,000 mmscfd

Imported LNG Gas

RM41.68/mmBTU for gas volume > 1,000 mmscfd

Imported Coal

USD87.50/MT At exchange rate 1 USD = RM 3.1 (RM 271.25/MT)

Notes: mmBTU = million British thermal unit mmscfd = million standard cubic feet per day MT = metric tonne

Generation component of the Base Tariff is subjected to a 6-monthly revision via ICPT Base tariff 2014-2017 sen/kWh

38.53

Generation costs 68.5%

Grid operator costs Transmission costs Distribution and retail costs

26.39

0.19 0.05 3.66

Subject to 6-monthly revision to reflect changes in fuel and generation costs

Single Buyer Operation Costs

Fixed for 2014-2017 8.24

ICPT

Tariff increased by 4.99 sen/kWh effective 1st Jan 2014

38.53 Source of tariff increase 2014, sen/kWh 3.92 Piped gas 14.89% 4.99 sen/kWh

LNG

33.54

2013

Gas price

Percentage of increase

Coal

78.6%

▪

LNG: RM41.68/mmBTU

▪ Piped gas: increased to RM15.20/mmBTU from RM13.70/mmBTU

Non-Fuel

3.4%

▪

Increased to USD 87.50/tonne from USD 85/tonne

18%

▪

To account for capex and opex for FY 2014 to FY 2017

2014 The bulk of the increase was due to the removal of gas subsidies and introduction of LNG at market price

1

Economic Regulation

2

Incentive Based Regulation (IBR)

3

Base Tariff - 1st January 2014

4

Imbalance Cost Pass-Through (ICPT)

5

Performance Indicators

IBR Regulatory Period timeline and ICPT review

Interim Regulatory Period

First Regulatory Period  (RP1)

2015

2014

Jan

Jul

Dec Jan Mar

Jun Jul

2016

Dec Jan

Jun Jul

Base Tariff 38.53 sen/kWh

2.25 sen/kWh rebate

2.25 sen/kWh rebate

1.52 sen/kWh rebate

Base Fuel Price

(726.99) RM/mn

(1,085.67) RM mn

(762.03) RM mn

Imported LNG RM 41.68/mmBTU Imported Coal RM 271.25/MT Domestic Piped Gas RM 15.20/mmBTU

RM 2.57 billion Total ICPT rebate passed through up to June 2016

2017

Dec Jan

Jun Jul

ICPT review every 6 months

Dec

ICPT for January – June 2016 Fuel Price Trend (Jan 2014 vs Dec 2015)

Cost Difference between Base and Actual

Imported LNG RM 41.68/mmBTU

RM 31.32/mmBTU

Generation & Fuel Cost Savings

Domestic Piped Gas Subsidy Rationalisation

ICPT Jan-Jun 2016 Base Tariff 38.53 sen/kWh

Imported Coal RM 271.25/MT

Rebate of 1.52 sen/kWh + RM 560 mn

RM 248.18/MT @4.056 RM/USD

(RM 762 mn)

Domestic Piped Gas RM 18.20/mmBTU

(RM 1,322 mn)

RM 15.20/mmBTU

The cost savings of RM 762 million has resulted in the electricity tariff rebate of 1.52 sen/kWh for Jan – Jun 2016

ICPT Rebate Impact to Customers (Jan - Jun 2016)

Domestic

ICPT

1.52

Commercial sen/kWh

REBATE

Savings* Impact

4.58 per month

From RM

 All customers with consumption > RM 77/month (>300 kWh/month) • Lifeline Band (0-200 kWh) rate at 21.8 sen/kWh. No change since 1997;

Subsidies

Note:

• Rate for 201-300 kWh at 33.4 sen/kWh. No change since 2009; • RM 20 Government subsidy enjoyed by around 1 million customers

Industrial

1.52 REBATE

1.52 REBATE

Savings*

Savings*

sen/kWh

Up to

4.0 %

 All customers

sen/kWh

Up to

5.1 %

 All customers

1

Economic Regulation

2

Incentive Based Regulation (IBR)

3

Base Tariff - 1st January 2014

4

Imbalance Cost Pass-Through (ICPT)

5

Performance Indicators

Performance Indicators under IBR

To ensure TNB’s performance are in line with the whole concept of IBR to promote efficiency

To encourage competition in regulated business of TNB

Reward and penalty system based on performance

G T D

Under IBR, TNB is monitored by ST for its operational and customer service performance Guidelines

Penalty / Incentive Scheme

Incentive slope

Penalty slope Note: For Trial and RP1 (2014-2017), PIs are only monitored by ST with no monetary impact

Performance indicators for TNB business entities

Business Customer Services

Transmission

System Operator 

CSPI1

SAIDI

Weightage (%) 50

CSPI2

Average of MSL Compliance Performance

25

CSPI3

Weighted Average GSL (3, 4 and 5)

25

TXPI1 TXPI2 TXPI3

System Minutes System Availability Project Delivery Index

100 40 30 30 100

SOPI1

Wide Area Loss of Supply Event

25

SOPI2.1

Security Limit Compliance: Voltage Limit Compliance (VLC)

25

SOPI2.2

Security Limit Compliance: Frequency Limit Compliance (FLC)

25

SOPI3

Dispatch Adjusment

SBP1

System Average Cost Compliance to Timely Settlement of Generators' Invoices

Code

SBPI2 Single Buyer 

SBPI3 SBPI4

Performance Indicator  

 

Percentage Compliance to Malaysian Grid Code (MGC) Percentage Compliance to single Buyer Rule (SBR)

25 100 25 25 25 25 100

Note: MSL: Minimum Service Level

IBR performance indicators achievements (I)

Business Entities

Performance Indicators

Note: Status for: Incentives

FY 2014

Status

FY 2015

Status

49.66 min/year/cu stomer

Incentive

54.95 min/year/cust omer

Incentive

 Average of MSL Compliance Performance

84.11% 94.11%

97.36%

Incentive

93.95%

Neutral

Weighted Average GSL (3,4 and 5)

86.32% 95.5%

99.13%

Incentive

99.71%

Incentive

1.5 – 5.1 min

0.1328 min

Incentive

0.7741 min

Incentive

System Availability

99.04% 99.48%

99.11%

Neutral

99.73%

Incentive

Project Delivery Index

0 – 5.47 months

-1.45 months

Incentive

1.38months

Incentive

System Minutes

Transmission

Achievements

55 – 70 min/year/cust omer

SAIDI

Customer Services

Dead Band

Neutral

Penalty

IBR performance indicators achievements (II)

Business Entities

Single Buyer

Performance Indicators

Dead Band

Dispatch Deviation

FY 2014

Status

FY 2015

Status

0% - 5%

-1.4%

Incentive

-2.5%

Incentive

Compliance to Timely Settlement of Generators’ Invoices

99.55% 99.85%

100%

Incentive

100%

Incentive

Non-Compliance to Malaysian Grid Code (MGC)

2 to 7 occurrences

0 occurrence

Incentive

0 occurrence

Incentive

2 occurrences

Neutral

4.5 occurrences

Neutral

Non-Compliance to Single Buyer Rule (SBR)

System Operations

Note: Status for: Incentives

Achievements

2 to 7 occurrences

Wide Area Loss of Supply Event

Less than 0 occurrence

0 occurrence

Incentive

0 occurrence

Incentive

Security Limit Compliance : Voltage Limit Compliance (VLC)

90% - 96%

100%

Incentive

100%

Incentive

Security Limit Compliance : Frequency Limit Compliance (FLC)

90% - 96%

100%

Incentive

100%

Incentive

Dispatch Adjustment

0.2% - 0.4%

0.0137%

Incentive

0.0156%

Incentive

Neutral

Penalty

Incentive and penalty caps for TNB business entities

Incentive

Neutral

▪  An incentive is applicable if actual performance is above the upper bound target

▪ No penalty or incentive is applicable if actual performance lies between the lower and upper bound targets

Penalty

5

10

▪  A penalty is applicable if actual performance is less than the lower bound target

BE

Total Incentive

BE

Total Penalty

CS

+0.3% ARR

CS

-0.3% ARR

TX

+0.3% ARR

TX

-0.3% ARR

SO

+0.5% ARR

SO

-0.5% ARR

SB

+0.5% ARR

SB

-0.5% ARR

Disclaimer All information contained herein are solely for the purpose of this presentation only and cannot be used or referred to by any party for other purposes without prior written consent from TNB. Information contained herein is the property of TNB and it is protected and confidential information. TNB has exclusive copyright over the information and you are prohibited from disseminating, distributing, copying, reproducing, using and /or disclosing this information.

Thank You

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Back Ups

Incentive-based rating (IBR) links revenues to delivery of OPEX and CAPEX efficiencies over time Enforce efficiency on costs

Description

▪  All operator costs are covered ▪ No incentives to improve Cost-plus

▪ ▪ The utilities set the tariffs to customers. ▪ Resulting tariffs are subject to the scrutiny of

Lefthanded regulation

the regulator who may require mandatory changes

▪ Initially (at year 1 of tariff), all operator costs are Performance-based Rating (IBR)

▪ Does not encourage

▪

covered (including fair cost of capital) In following years, a cap, either on revenues or unit costs 1, is applied to incentivise efficiency

1 Applies to “controllable” system costs that are not subject to market forces (i.e. excluding fuel price)

efficiency No upside for operators

▪ Need for a careful ▪

monitoring More flexible, but uncertain

▪ Ensures fair returns ▪ Forces efficiency ▪ Ensures transparency

1 Load Forecast forms the basis for other forecasts in IBR submission

Load Forecast

Opening Asset Base

• • •

Capex & Opex forecast

Other parameters

Generation forecast (GWh) Sales forecast (GWh) Demand forecast (MW)

Snapshot of the IBR Process

• • • • •

•

Common parameters e.g forex, inflation, staff cost

Tx

escalation, insurance, quit

CS

rent etc.

SB (O)

•

SO

Generation-related e.g. fuel prices forecast, RE

Joint Costs

displaced cost, dispatch plan, PPA/SLA commercial

Base Generation Cost

terms etc.

Inputs for RRM

2 RRM is used to determine the revenue requirement for all BEs and average tariff

IBR Rev. Requirement Model (RRM)

Revenue

• WACC x RAB

Requirement

• Opex • Depreciation • Tax payments

Average Tariff

• Efficiency carryover

3 Tariff design to ensure revenue recovery

COS study

Micro tariff design and rebalancing

Customer segmentation

Macro tariff design

Marginal cost International tariff comparison Impact study

ST is embarking on RIGs Review

IBR RP2 Timeline – Phase I Key Milestones Preliminary Load Forecast/Common Parameters Assumption Review and Consultation with ST on RIGs Draft BEs Submission (for RRM)

Revised Timeline Council 25 th Apr 2016)

(6th IBR

End Feb 2016

May – Aug 2016 End May 2016

Completion of RIGs Review

Aug 2016

Final Load Forecast / Common Parameters Assumption

Aug 2016

Revised BEs Submission (for RRM)

Sep 2016

IBR Report Drafting/Writing

May until Mid-Sep (4 ½ months)

Draft Final IBR Report

Mid-Sep 2016

JEK’s Approval

End Sep 2016

Board of Director’s Approval

End Oct 2016

Final IBR Submission to ST

Dec 2016

Base Tariff was set at 38.53 sen/kWh from 1 January 2014

This rate of return is necessary to allow for investment in electricity infrastructure to meet increasing demand…

Capital Expenditure RM billion

8.5 7.3

Source: TNB Analyst Briefing 4QFY2015

10.8 10.0

…as well as to achieve world class performance standards

Generation

EAF, %

Transmission

System Minutes, minutes

2.5%

Distribution

SAIDI minutes/customer/year 

-20%

-37%

0.8

2011

2015

EAF : Equivalent Availability Factor SAIDI : System Average Interruption Duration Index

2011

2015

2011

2015

Actual coal prices in USD/MT show a downward trend…

Benchmark price in tariff, USD/MT  Average Coal Price (ACP), USD/MT

USD/MT

Benchmark coal price set in Jan’14 tariff revision

USD/MT

Jan – Mar ‘14

 Apr – Jun ‘14  Jul – Sep ‘14

Oct – Dec ‘14 Jan – Mar ‘15  Apr – Jun ‘15 Jul – Sep ‘15

Oct – Dec ‘15 Jan – Jun ‘16

However, it is picking up and approaching the benchmark price after taking into account the depreciation of Ringgit Benchmark price in tariff, RM/MT  Average Coal Price (ACP), RM/MT Benchmark coal price set in Jan’14 tariff revision

RM/MT

271.25

RM/MT

259.85

256.73 250.36

248.18 241.07

236.24

237.19 226.30

Jan – Mar ‘14 Base Fx Actual Fx

 Apr – Jun ‘14  Jul – Sep ‘14

Oct – Dec ‘14 Jan – Mar ‘15  Apr – Jun ‘15 Jul – Sep ‘15

3.1

3.1

3.1

3.1

3.2273

3.3096

3.2717

3.2468

*Note: 1 - Exchange rate is: 1 USD to RM

224.55

Oct – Dec ‘15 Jan – Jun ‘16

3.1

3.1

3.1

3.1

3.1

3.3702

3.6304

3.6362

4.0560

4.2950

Liquefied Natural Gas (LNG) was below benchmark price since Q3 2015

 Actual price billed by PETRONAS Benchmark price in tariff Revised price by PETRONAS1 RM/mmBTU

48.57 47.44 45.84

LNG Price for Q4’15 (as per PETRONAS)2

Benchmark LNG price set in Jan’14 tariff revision

Jan – Mar ‘14  Apr – Jun ‘14  Source: Single Buyer Department, TNB

Note:

Jul – Sep ‘14

Oct – Dec ‘14

Jan – Mar ‘15  Apr – Jun ‘15

Piped gas price to the power sector is gradually reviewed as part of Government’s subsidy rationalisation programme Jan ‘16: RM 1.5/mmBTU increase

Jul ‘15: RM 1.5/mmBTU increase

RM/mmBTU Benchmark piped gas price set in Jan’14 tariff revision

18.20 16.70 15.20

Jun ‘11

Jan ‘14

Jul ‘15

Jan ‘16

IBR is a structured way to set electricity tariff

Before IBR • • •

After IBR

Tariff setting was on ad-hoc basis No proper mechanism for tariff review Less transparent to customers

ICPT Base Tariff

ICPT every 6 months Base tariff is reviewed once in every 3 years

Example: Similar mechanism is adopted for Petrol/Diesel price setting Managed Float Mechanism • Based on market prices • Monthly revision

RIG 2 : Define Implementation Tariff Setting Framework (2/2) (RIGs) Regulatory Guidelines

Revenue Cap What it is

Advantage/s

Disadvantage/s

Price Cap

•

Regulates the maximum allowable revenue that a utility can earn

•

Price cap sets the maximum price that a utility can charge

•

It is the utility’s revenue, not its rates, that is capped

•  Also called rate caps, price indexing or rate indexing

•

More compatible with utilities that are facing substantial demand response management programs or energy efficiency reductions in consumer demand

•

•

Provide more pricing flexibility, easier to implement, and preferable when costs do not vary significantly with sales volume

•

Requires accurate forecasts of actual CAPEX and OPEX

•

Actual Cost •

Pass-through of all costs for procuring electricity

Provides the utility a degree of flexibility on how to optimize specific customer rates and consider cost allocations

•

Ensures that the regulated entity does not earn less than the cost of providing the services

Utility bears volume risk of any shortfall in demand (but is also rewarded by demand growth)

•

Gains cannot be retained by the entity and must be returned to customers in the following regulatory term

•  Actual cost adjustments take place only twice a year

TNB Business Entities

Single Buyer Operations

Transmission System Operations

Customer Services

Single Buyer Generation

RIG 1 : Define Business Entity (3/x)

Electricity Customers

•

The Customer Services business entity charges electricity customers a bundled tariff for the use of electricity.

•

Customer Services pays Transmission, based on a Transmission Tariff and System Operations based on System Ops Tariff

•

Customer Services pays Single Buyer based on Generation Tariff (comprising a generation specific component and a component for other operational costs of the Single Buyer). The Single Buyer pays TNB Generation based on SLAs & IPPs based on PPAs

Flow of Funds

Electricity Tariff 

Customer Services

Generation Tariff 

Transmission Tariff 

Transmission

System Operations Tariff 

System Operations Single Buyer SLAs and merit order dispatch

TNB Generation

PPAs and merit order dispatch

Independent Power Producer (IPPs)

Managed Market Model

RIG 1 : Define Business Entity (4/x)

Electricity Customers

Efficiencies achieved by Incentive based regulation (IBR) • Building block model used to

(Connected to the Distribution System)

develop revenue requirement

Electricity Tariff

•

Distribution (Customer Services) Transmission Tariff

Single Buyer Tariff

Transmission

System Ops Tariff

Appropriate price control mechanisms developed by the Energy Commission.

System Operations

Single Buyer* PPAs and merit order dispatch

SLAs and merit order dispatch

TNB Generation Others (RE, imp/exp etc)

IPPs

Efficiencies achieved by Single Buyer Rules SBR • Least cost dispatch • Transparent operations • Governance arrangements

RIG 6 : Establish Incentive Framework for Operational Performance (3/3) S-Curve for the performance indicators of business entities

Customer Services

System Operator (SO)

Transmission

Single Buyer (SB)