Economics of Price Regulation - ERRA€¦ · ERRA Tailor-made Training Course: Principles of Tariff...

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ERRA Tailor-made Training Course: Principles of Tariff Regulation

Implemented for: Oman Power & Water Procurement Company

December 2-4, 2018 • Muscat, Oman

Economics of Price

Regulation

Ardian Berisha

Energy Regulators Regional Association

2ERRA Tailor-made Training Course: Principles of Tariff RegulationDecember 2-4, 2018 • Muscat, Oman

Contents

• Economics of Regulation

• Tariff regulation in practice

• Energy balance

• Regulatory Asset Base

• WACC, Depreciation and Return

• Cost recovery principles

• Tariff review process

Where and when to regulate

• Generation and Supply prices

• Market concentration

• Market Power

• Inefficient markets

• Transmission and distribution charges

• Natural Monopolies

• Regulated to move production towards

socially optimal prices

Where and When to regulate

• Herfindahl-Hirschman Index

• Commonly-accepted

indicator of market

concentration

• Square the market shares

of the firms operating in

the market

𝐻𝐻𝐼 = 𝐺12 + 𝐺2

2 + 𝐺32 +⋯+ 𝐺𝑛

TSO/MO

Where and When to regulate

Example

G1=30%, G2=50%, G3=20%

𝐻𝐻𝐼 = 302 + 502 + 202

= 900 + 2500 + 400 = 3800

TSO/MO

S S SHHI Index Market Concentration*

0-1500 Competitive market

1500-2500 Moderately concentrated market

>2500 Highly concentrated market

*As per U.S. Department of Justice

Economics of Regulation

• Demand curve (D)

• Total Costs (TC)

• Fixed costs (FC)

• Variable costs (VC)

• Average Total Costs (FC+VC)/Q

• Total Revenue (TR) p x Q

• Marginal Revenue (MR) – dTR/dQ

• Marginal Costs (MC) – dTC/dQ

• Profit (𝜋) = TR-TC

Econ101 - Demand

• The relationship between

the Price (p) of a product

and its quantity demanded

(q) is reflected in the

Demand Curve

• For any q, there is a max p

that customers are willing

to pay and vice-versa

• The lower the price the

higher the quantity

demanded, as

characterized by the

negative slope of the curve

More basic

products

Less-basic

products

Consumer Surplus

Econ101 – Consumer surplus

• For any quantity demanded

up to q*, consumers were

willing to pay a price above

p*, up to the price

corresponding with the

demand-curve

• The area between the

demand-curve and the

Market Price is therefore a

surplus to consumers, known

as the Consumer Surplus

• Consumers are better off if

the area of consumer surplus

increases

Market

Additional Surplus

Econ101 – Natural Monopoly

• Average Total Cost curve

downward sloping for the whole

range of production;

• If the range of demand is split

equally between two firms, then

they would experience costs of

• If only one firm supplies the

whole range of demand then

they can benefit from

economies of scale and the

average total cost for providing

a higher number of output is

lower (c1)q*

Why should it be regulated

Economic profit

• If left unregulated, Monopolist

follows profit-maximizing rule

and produces at a q where

• Monopolist charges at pm

because that’s the price

consumers are willing to pay for

that level of quantity

• Consumer surplus is reduced

compared to a scenario where

quantity would be set where

marginal benefit is equal to MC,

represented by the D-curveqm

Inefficient but still better off (reminder)

Economic profit

Unregulated monopoly ATC-pricing

Possible remedies (1/3)

• Apply two part tariffs

• Apply a fixed charge (capacity charge or customer

charge) to cover fixed costs;

• Apply a variable charge (energy charge) to recover those

costs which change with the level of production and set

to MC;

• Regulated monopoly receives the same total revenue

(albeit from different “sources”)

• More efficient unless customers are priced-out of the

market

• Apply fixed charge in inverse proportion to elasticity of

demand

• Apply optional tariffs which better suit the

consumption preferences;

• Some customer prefer higher fixed costs and

lower variable cost. Others prefer a higher

average cost but no connection/standing/fixed

charge;

• Adjusting to these preferences, subject to cost

recovery, can increase total welfare.

• Apply Ramsey-Boiteux pricing

• Use elasticity of demand as an indicator of customer

likeliness to reduce consumption as a result of the

fixed tariff

• Apply prices closer to MC to consumption which is

more elastic

• Apply prices closer to AC to consumption which ir

more inelastic

Examples of MC and ATC pricing

Assumptions:

Fixed cost of providing service = €95,000,000

Variable cost of providing service =39 €/MWh

𝑇𝐶 = 95,000,000 + 39𝑄

Demand function

𝑄 𝑝 = 15,000,000 − 90,000𝑝

Total revenue

𝑇𝑅 = 𝑝 ∙ 𝑄 𝑝 = 15,000,000𝑝 − 90,000𝑝2

Example (Marginal Cost pricing)

Regulator sets prices at MR=MC

(Qd=11.49 TWh)

𝑇𝐶 = 95,000,000 + 39𝑄

𝑀𝐶 = 39 => 𝑃 = 39

Profits

𝜋 = 𝑇𝑅 − 𝑇𝐶= 39 ∗ 11.49 − 95,000,000 + 39 ∗ 11.49

𝜋 = −95,000,000

Company does not recover fixed costs

MC=PATC

Losses

Example (Average Total Cost 1/2)

𝑇𝐶 = 95,000,000 + 39𝑄

𝑄 𝑝 = 15,000,000 − 90,000𝑝

𝑇𝑅 = 𝑝 ∙ 𝑄 𝑝= 15,000,000𝑝 − 90,000𝑝2

Solve for TC as a function of p

𝑇𝐶 =

=95 ∙ 106 + 39(15 ∙ 106 − 90,000𝑝)

Solve quadratic TR=TC

𝑝 = 47.87 𝑄𝑑 = 10.6 TWh

Example (Average Total Cost 2/2)

What is the deadweight loss to society?

Area of the purple triangle

𝐴𝑟𝑒𝑎 =1

2∙ 𝑏 ∙ ℎ =

2∙ 11.49 − 10.6 𝑇𝑊ℎ

∙ 47.9 − 39.0 €/𝑀𝑊ℎ= €7.1𝑚

Example (Two-part tariffs)

Principle:

• Recover fixed costs through a

standing/fixed/per-customer charge

• Recover variable costs through MC-

pricing

Assume S=450,000 customers

𝐶𝑢𝑠𝑡. 𝑐ℎ𝑎𝑟𝑔𝑒 =95,000,000

450,000= 211.1

𝐸𝑛𝑒𝑟𝑔𝑦 𝑐ℎ𝑎𝑟𝑔𝑒 = 𝑀𝐶 = 39 €/𝑀𝑊ℎ

Comparison

• Two-part tariffs favor

large consumers due to

the presence of a fixed

• In this case all consumers

up to 263.75 kWh are

better off with an average

• Those customer can be

priced-out of the market,

leading to inefficient

outcomes

0 50 100 150 200 250 300 350 400 450 500

monthly kWh consumption

ATC avg price

2-part Avg Price

Regulation in practice – chart of contents

lessexport

revenues

plusImport

Purchase Costs

Power Purchase Costs

Subsidies

Unregulated Income

Maximum Allowed

Revenues (MAR)

Operating Expenses

DepreciationAllowed Return

Wholesale Power

Purchase Costs

Regulatory Asset BaseRABt=(RABt-1)-DEP+CAPEX

multiplied byWACC

divided byAsset Life

+ + + - =

Investment Plan Energy Balance

TSO revenue-setting process

Capital Costs

MAXIMUM ALLOWED REVENUES (MAR)

Operating Expenditures Deductions from MAR

Allowed Return

Depreciation

Asset LivesRAB

WACCRAB Other Operating Costs

Base Opex

Maintenance Costs

Cost of Losses [TSO]

Personnel Costs

Cost of Ancillary Services [TSO]

Inter-TSO Compensation Mechanism (ITC) [TNO]

Other Non-Tariff Income

Energy Balance

• The Energy Balance is the main input sheet of the

MAR calculation and is the main driver behind the

revenue components;

• Energy balance drives investment in generation,

transmission and distribution infrastructure;

• Built using the bottom-up approach with the

expected level of sales being the main determinant

of all the other values;

• Energy required to meet domestic demand is

calculating by adding allowed level of losses to the

expected sales at both T and D-level;

Energy Balance

Energy Balance Year 1 Year 2 Year 3 Year 4 Year 5

Energy Entering Transmission System GWh 4,089.4 4,446.6 3,809.7 4,216.9 4,223.8

Transmission Losses % 1.7% 1.7% 1.8% 1.7% 1.7%

GWh 111.2 112.6 110.3 109.0 107.0

Energy Required to meet Transmission Load GWh 3,978.2 4,334.0 3,699.4 4,107.8 4,116.8

Transmission-level sales 553.0 947.0 542.0 858.3 867.3

Aluminium plant 1 GWh 449.0 842.0 434.0 687.0 700.0

Aluminium plant 2 GWh 104.0 105.0 108.0 108.0 104.0

Industrial plant 3 GWh 63.3 63.3

Energy Required to meet Distribution Load GWh 3,425.2 3,387.0 3,157.4 3,249.6 3,249.6

Distribution-embedded generation GWh 110.0 120.0 130.0 140.0 140.0

Distribution-level sales GWh 3,535.2 3,507.0 3,287.4 3,389.6 3,389.6

Distribution losses and unbilled energy

Technical and commercial losses % 8.0% 7.0% 6.0% 6.0% 6.0%

GWh 282.8 245.5 197.2 203.4 203.4

Sales to final customers GWh 3,252.4 3,261.6 3,090.1 3,186.2 3,186.2

Inclusion of Capex into RAB

• Main challenge for regulators: The appropriate

level of capex to be recovered from regulated

tariffs

– Asymmetry of information (regulated entity is better

informed about the level of capex and the associated

– Incentive to inflate costs (so as to gain on the difference

between the approved and actual cost)

– Incentive to increase total investments (also referred to

as “gilding” – occurs when there are differences between

allowed and actual cost of capital - WACC)

Asset lives

• Used to calculate Depreciation allowance for regulated utility

RABt/Asset life=DEPCt

• Distinguish between technical and economic asset lives

• Asset life set to technical life, unless specifically demonstrated by utility that this is not the case (use economic lives instead)

Smoothing and profiling of capex

OECD study on Infrastructure Investment

• OECD conducted a study on Fostering investment

in infrastructure (2015)

• Lessons learned from country experiences in

enhancing private sector participation and end-

user affordability in infrastructure sectors were

compiled

“Increasing private participation in infrastructure

investment requires an investment regime that

provides clarity and predictability for investors…”1

1OECD Fostering investment in infrastructure (January 2015)

WEF study on Strategic Infrastructure Risk

MitigationRisk Mitigation Framework2

2 WEF Study on Mitigation of political and regulatory risks in Infrastructure project Risk Mitigation Framework (2015)

Reducing investor risk

• Facilitating infrastructure investment requires a

stable and predictable regulatory framework which

provides clarity to investors;

• Regulators should seek to reduce discretionary

practice when assessing/reviewing the

reasonableness of capex plans by having defined

evaluation criteria

• Gradually building regulatory credibility

increases investor confidence and reduces cost of

capital, ultimately providing added value to

customers.

Inclusion of Capex into RAB (1/4) (rewind)

Main challenge for regulators: The appropriate

level of capex to be recovered from regulated

tariffs– Asymmetry of information (regulated entity is better

informed about the level of capex and the associated

– Incentive to inflate costs (so as to gain on the difference

between the approved and actual cost)

– Incentive to increase total investments (also referred to

as “gilding” – occurs when there are differences between

allowed and actual cost of capital - WACC)

Inclusion of Capex into RAB (2/4)

Regulators often apply both ex-ante and ex-post reviews in

order to match allowed and actual capex

Ex-ante (before the commencement of the Regulatory Period)

the Regulator assesses the necessary capex of the Regulated

entity and the associated cost

– Extension expenditure assessment

– Replacement expenditure assessment

– Proposed costs are weighed against investment databases and

previous allowances

– Regulators may choose to study specific projects which are major

investment cost drivers (ex. new HV lines, large SS installations, etc)

– Benchmarking studies, independent consultancy reviews, prudency

tests are often conducted.

Ex-post assessments are conducted to supplement

ex-ante reviews conducted prior to the Regulatory

Period

Differences between allowed and actual costs are

reviewed by the Regulator:

– Differences due to strategic deferrals from the base

– Differences due to (in)efficient investment

procurement and management;

– Regulator may choose to claw back differences in

costs (if actual<allowed) or compensate the utility (if

actual>allowed)

Ex-post regulatory review can be conducted without

ex-ante approvals

– Under such schemes, the regulated companies would be

incentivized to only invest in highly efficient investments

which they believe would be allowed by the Regulator;

– On the other hand regulated companies are exposed to

the risk of having their having their capital investments

disallowed and therefore not recovering investment

costs.

– This may reduce capital investments and place the mid-

term to long-term security and quality of supply at risk

RAB build-up

Opening RAB 2018

Approved Capex RP1

Depreciation RP1

Closing RAB RP1

Opening RAB RP1

Pre-approved Capex 2018

Depreciation 2018

Closing RAB 2018+ - =

Opening RAB2019

-> to 2022

What RAB value?

• Cost-Based approach

• Historic cost• Value at the price paid for the assets when commissioned

• Investors recover cost paid for the asset

• Customers pay the actual cost of the investment

• Current cost• Value at the current cost of using the asset

• Economic efficiency – costs of serving at this point in time

• Technological change implies change in value

• Economic value • Value generated by the asset

• Circularity issue

What RAB value: Current cost

• Current cost evaluation

Indexation

• Adjust historic value of assets using cost index (CPI, HICP)

Replacement cost

• Revalue at the current cost of purchasing the same asset

Modern Equivalent Asset

• Revalue at the current cost of the asset with the same capability

Optimized replacement cost

• Determine optimal network design required to provide same service and value assets at its costs

What RAB value: economic value

• Economic value of

income generated

by the assets

• Takes into account

broader picture:

performance of the

company, bad

debts, losses

• Circularity issue

RAB is economic

Economic value based

on net income

Net income=

D + R + Opex

R component depends on

CAPEX Benchmarking tools (1/2)

• Overview of main regulatory models (RoR,

Price/Revenue cap, Yardstick regulation)

• Major capex assessment models

• Regulatory tests (NPV, IRR, CBR, PBP)

• Standard cost approach (using unit costs to

determine ex-ante reasonableness EUR/km of

0.4 kV line)

• Econometric models (OLS)

• Integrated Efficiency Analysis

CAPEX Benchmarking tools (2/2)

Source: Konstantin Petrov’s presentation on capex benchmarking tools, Budapest (2018)

Overview of benchmarking approaches in

Europe

Source: Srini Parthasarathy presentation on European approaches to benchmarking capex, Budapest (2018)

Asset utilization, stranded assets (1/2)

• Asset stranding can happen as

a result of reduced volumes

(environmental policy

objectives, role of gas) or

changing market conditions

(abolishment of PPAs)

• Regulator’s role in recovering

stranded costs

• Depreciation policy to

recover stranded costs;

• Asset valuation methods

• Premium return in WACC

against future volume

Source: Konstantin Petrov’s presentation on asset

utilization and stranded assets, Budapest (2018)

Weighted Average Cost of Capital (WACC)

• Represents the weighted average return required by debt and equity holders to invest in the regulated business

𝑊𝐴𝐶𝐶 = 𝑔 ∙ 𝑟𝑑 +(1 − 𝑔) ∙ 𝑟𝑒

g gearing ratio (calculated as d/(d+e))

rd return on debt

re return on equity

Weighted Average Cost of Capital (WACC)

• “Efficient” financing cost– 1a) Estimate an ‘efficient’ financing cost – estimating the

risk-free rate based on yield-to-maturity of Governmental

– 1b) Estimate an “efficient” financing co –risk-free rate

calculated based on another EUR denominated bond and

adjusted for additional risk factors

• Actual/historical financing cost– Set the cost of debt equal to the actual weighted average

cost of financing incurred by the licensees

– Reflect actual gearing ratio (subject to some reasonable

gearing domain – e.g. 0.4-0.7)

– Set the RoE according to CAPM estimations for others

Return on debt

𝑟𝑑 = 𝑟𝑓 + 𝐷𝑅𝑃

Whererd return on debt

rf Risk-free rate (proxied by the country’s sovereign debt bond yield)

DRP Debt Risk Premium – the additional premium that is associated with providing debt to a particular investor

10-year Yield rates in select EU countries

Yield rates have generally gone down…

Return on equity

• The “standard” approach applied by regulators in determining the Re is the Capital Asset Pricing Model (CAPM)

• According to CAPM, return required by investors is sum of rf rate plus a premium equivalent to equity risk premium, compensating for additional risk of investing in equity markets

• This ERP is multiplied by a coefficient (Beta) which adjusts for whether the risk of the particular investment is higher or lower than general risk in equity markets

Return on equity

𝐶𝐴𝑃𝑀 = 𝑟𝑓 + 𝛽 ∙ 𝐸𝑅𝑃Where

rf is the risk-free rate

β is the covariance between the return of the individual stock of the

company with the return of the market

ERP is the equity risk premium which represents the additional risk investors

face in holding equity shares

• Beta represents the volatility of the returns of a particular stock compared to the volatility of the returns of the whole stock market;

• If companies are not listed on the stock market then benchmarking analysis is used;

• Asset vs. Equity Beta should be taken into account in sampling, to reflect the fact that companies in the sample may have different leveraging levels

Beta values for EU countries

Electricity Transmission Beta Values across a range of EU countries

Source: ERRA research

Beta values for EnCT SP + ERRA Members

Georgia FYROMacedonia

Kosovo 3* Croatia*6 Montenegro(3)

Albania (3) Serbia (3)

Beta Values ERRA & ENCS

Equity/Market Risk Premium (ERP or MRP)

Illustration of WACC levels

Source: EY study: Mapping power and utilities regulation in Europe

Operating and Maintenance Costs

• Sum of all operating

and maintenance costs

required for providing

regulated service

• Main cost line items

include personnel

expense and

maintenance costs

• In some cases cost of

transmission/distributi

on losses included

Operating and Maintenance Costs

• Regulators set allowed

O&M costs by

comparing cost levels

between comparable

companies

(benchmarking)

• Efficiency factors

applied to encourage

savings to customers

(incentive-based

regulation)

Source: ERO provisional evaluation DSO Opex

Treating actual vs. allowed differences

• Set benchmark value

for 1st year of

Regulatory Period

• Apply efficiency factor

to incentivize savings

• Apply savings sharing

factor (0-100%) to

share benefits 15,0

2012 2013 2014 2015 2016E

Allowed vs. Actual Operating and Maintenance Costs

Allowed Opex Actual Opex

Setting the efficiency factor

Approach to starting value

Calculation of efficiency factor

Starting value set at 2016 actual values

• Efficiency factor includes removal of existing inefficiencies and general productivity improvement

Starting values set at ‘efficient’ cost levels

• Efficiency factor only includes general productivity improvement

Efficiency factor = general productivity improvement

+ licensee-specific inefficiency removal

Baseline efficiency factor = general

productivity improvement only

• Efficiency factor depends on how the starting

value is set

Setting a baseline efficiency factor

• A baseline efficiency

reflects efficiency gains

yielding from general

productivity on top of

economy-wide

productivity growth

• Refer to regulatory

decisions on

productivity growth

• Number of studies is

limited

Should efficiency gains be carried over?

• Company’s incentives to reduce costs fall towards

the end of the Regulatory period

• Companies accumulated gains are therefore higher

if efficiency is increased in first year of Regulatory

period rather than the last

Company gain Actual expenditure

Network losses

• Distribution losses can effectively be broken down into two

main categories:

• Technical losses – energy that is lost in the system for technical/physical reasons in line heating or transformers

• Commercial losses – energy that is delivered to

customers but not billed, and that is not technical

• A one percent decrease in technical losses represents

implies 1% less energy is required to be input to the grid

• A one percent decrease in commercial losses may

represent only a 0.2% less energy required to be placed to

the grid (energy is still consumed, only more efficiently)

Factors affecting network losses

Technical losses Commercial losses

Main factors affecting

• Condition of the grid• Lack of systematic

investment program• Grid overloads/wire

heating

• Lack of frequent and systematic checking of metering points

• LV metering devices easy to tamper

• Lack of rule of law• Lack of access to supply site

Possible remedies • Encourage investment in strengthening/replacing network

• Stable regulatory framework recovering the cost of investment

• Cost recovery tariffs

• Replace meters with those more difficult to tamper;

• Seal boxes and place in a visible position to avoid by-passing;

• Invest in PR, improve company reputation/credibility

• Engage in management to identify cooperating staff

Incentivizing Distribution loss reductions

t t+1 t+2 t+3 t+4 t+5

Periodic

Review

-x%-x%

-y%-y%

Where x>y

Example: Step 1 – Energy Balance

• Start with the level of sales at 1st Year of Regulatory Period. Increase this

value annually by the forecast percentage increase in sales (ex. 3%) as

shown in row (a)

• Divide final sales by (1-%AL) where AL is allowed losses in percentage terms

as shown in row (b) below

• This will give the total figure of energy that has to enter the network to

cover the sales + losses as shown in row (d). Deduct sales from this number

to get total losses (to get row (c))

units 2018 2019 2020 2021 2022

Allowed Allowed Allowed Allowed Allowed

First regulatory period

(a) Forecast sales GWh 3,179.0 3,274.4 3,372.6 3,473.8 3,578.0

(b) Allowed losses % 11.0% 10.0% 10.0% 9.0% 8.0%

(c)=(d)-(a) Allowed losses GWh 392.9 363.8 374.7 343.6 311.1

(d)=(a)/(1-(b)) Total distribution energy GWh 3,571.9 3,638.2 3,747.3 3,817.3 3,889.1

Example: Step 2 – Regulatory Asset Base

• Assume Opening RAB value is €148,940,000. Start with level of annual

investments you approved for the Regulatory Period (row (e))

• In year 1 of the Regulatory Period, add the approved investments to the

starting value (row (h))

• Calculate Depreciation by dividing the starting value and half of the annual

addition by the asset life (row (i))

• Add rows (g), (h) and (i) to get the closing balance in Year 1. This will be the

starting value in Year 2.

units 2018 2019 2020 2021 2022

(g) Opening balance €000 148,940.0 166,640.3 176,228.9 188,054.6 202,436.2

(h) Additions in year €000 23,049.1 15,400.0 18,000.0 21,000.0 18,000.0

(i)=-((g)+0.5*(h))/(f) Depreciation €000 -5,348.8 -5,811.3 -6,174.3 -6,618.5 -7,047.9

(j)=(g)+(h)+(i) Closing balance €000 166,640.3 176,228.9 188,054.6 202,436.2 213,388.3

Example: Step 3 – Return and Depreciation

• Calculate the WACC (in this case it’s given at 7.2%) and multiply by the

average of the opening and closing RAB values in a given year to calculate

allowed return (row (l))

• Present depreciation as the negative of the figure in row (i).

units 2018 2019 2020 2021 2022

(k) WACC % 7.20% 7.20% 7.20% 7.20% 7.20%

(l) = (k) x ((g)+(j))/2 Allowed return €000 11,360.9 12,343.3 13,114.2 14,057.7 14,969.7

(m)=-(i) Allowed Depreciation €000 5,348.8 5,811.3 6,174.3 6,618.5 7,047.9

Example: Step 4 – Opex and losses

• Assume you decided to apply a 3% Annual Efficiency Factor to O&M costs

from the 2nd to the 5th year of the Regulatory Period.

• Assume starting O&M costs in the first are €38,929,000

• Calculate Year 2 O&M by deducting 2% out of the starting value. Calculate

Year 3 O&M by deducting 2% from the resulting value in Year 2 and so on…

• Assume Wholesale Power Purchase Costs for Losses are set at 32.8 €/MWh.

• Calculate the cost of losses of by multiplying the volume of losses (row (c))

with the average price in row (p).

units 2018 2019 2020 2021 2022

(n) Efficiency Factor % 3.00% 3.00% 3.00% 3.00%

(o)=Allowed(t-1)*(1-(n)) Allowed O&M €000 38,929.0 37,761.1 36,628.3 35,529.4 34,463.6

(p) WA Power Purchase Cost €/MWh 32.8 32.8 32.8 32.8 32.8

(q) Cost of losses €000 12,887.5 11,933.3 12,291.3 11,268.8 10,205.1

Example: Add (l) (m) (o) and (q) to get MAR

units 2018 2019 2020 2021 2022

(k) WACC % 7.20% 7.20% 7.20% 7.20% 7.20%

(l) = (k) x ((g)+(j))/2 Allowed return €000 11,360.9 12,343.3 13,114.2 14,057.7 14,969.7

(m)=-(i) Allowed Depreciation €000 5,348.8 5,811.3 6,174.3 6,618.5 7,047.9

(n) Efficiency Factor % 3.00% 3.00% 3.00% 3.00%

(o)=Allowed(t-1)*(1-(n)) Allowed O&M €000 38,929.0 37,761.1 36,628.3 35,529.4 34,463.6

(p) WA Power Purchase Cost €/MWh 32.8 32.8 32.8 32.8 32.8

(q) Cost of losses €000 12,887.5 11,933.3 12,291.3 11,268.8 10,205.1

(r) = (l)+(m)+(o)+(q) Total MAR €000 68,526.2 67,849.0 68,208.1 67,474.4 66,686.2

Adjustments within the Regulatory Period

Actual

(2015)

Allowed

(2015)

Actual

(2016)

Proposed

Allowed Losses

Percentage of allowed losses % 1.84% 1.80% 1.74% 1.80%

Assumed transmission flows GWh 5,916.4 6,162.9 6,313.4 6,331.8

Weighted average power purchase costs €/MWh 31.2 28.24 30.3 32.7

Actual allowed cost of losses 2.9 3.2

Forecast allowed cost of losses 3.1 3.7

LSACt-1 €m 3.0 3.1

LSSCt €m 3.0 3.9

Reward for achieving the loss target -0.14

*Loss sharing factor 50%

Pricing principles

• 2015 EC study on tariff design for distribution systems

System sustainability Economic efficiency Protection of stakeholders

Tariffs should be sufficient to fully recover costs

Productive efficiency (efficient investments and operational expenses)

Transparenct methodology is published and available to all parties

There should be an adequate rate of return proportional to the risks

Allocative efficiency (avoidconsumption from peak, flexible)

Non-discriminatory pricing between categories

Achievable incentive components (i.e. targets)

Cost reflective – charges reflect the cost of service

Equitable, simple and predictable tariffs

Tariff components must add up to equal the total revenue allowed

Innovation promotional –tariffs should not be a barrier to innovation

Stable and consistent tariff regulation and regulatory framework

Marginal Cost pricing

• The Marginal Cost is the

additional incremental cost

which results from providing of

an additional unit of output

• For the distribution system, the

marginal cost of distributing

another unit of electricity is

almost zero, as long as there is

spare capacity

• If there is no spare capacity

then MC is high (due to

necessary investments)

• We use LRMC in order to avoid

price jumps when there is no

spare capacity and investments

have to be made

Spare capacity

Marginal cost

Average costInvest-

LRMC = Long-run Marginal Cost

growth related opex is the incremental annual cost of operating and

maintaining the newly constructed network and connection assets

over the forecast period;

growth related capex is the annualized capital expenditure to meet

the additional demand

incremental demand is the forecast change in kW demand

compared to the base year

• The growth-related opex part is relatively

simple to determine because opex has a

more defined relationship with increasing

demand (generally linked to fuel costs, for

example);

• Determining the growth related capex is

more complicated because it accounts for

investments associated with an increase in

demand

1. Prepare forecast demand characteristics (line a)

2. Estimate cost of additional investment to meet characteristics (line b)

3. Calculate LRAIC as ratio between (b) and (a)

4. Calculate Annuity of LRAIC and add Opex-related LRMC to get the total LRMC

Calc. Item 2017 2018 2019 2020 2021

- Weighted Average Asset Life years 20

- Weighted Average Cost of Capital (WACC) % 8.80%

a Incremental load MW 20 25 30 30 30

b NPV 104

c Investments 000 € 4,490 4,951 5,153 5,349 5,649

d NPV 19,833

e=d/b LRAIC €/kW/yr 190.9

f Annuity of LRAIC €/kW/yr 20.6

g Long-run O&M costs €/kW/yr 5.2

h=f+g LRMC €/kW/yr 25.8

Revenue-setting process

• Tariff-setting is a complex technical process

• Impacts tend to be oversimplified by civil society/media – high social

pressure. Keeping stakeholders involved is key

• Reduces possibilities of external intervention/arbitrary decision making

• Enhances independence

• Increases investor confidence, reduces cost of capital

Outline process and share with stakeholders

Step 1

Preliminary applications

received

Step 2

Final applications

received

Step 3

Regulatory public

consultation

Step 4

Response to comments

paper issued

Step 5

Final regulatory

decision taken

Step 6

Key messages to take away (1/3)

• Regulate only natural monopolies or those

competitive segments where market

produces inefficient outcomes

• Natural Monopolies occur when the

demand of the whole market can be

supplied at a lower cost by one firm than

more firms due to economies of scale

• Setting prices to marginal costs provides

efficient outcomes but does not recover

fixed costs

• Setting prices to average costs recovers

total costs of service but consumption is

reduced therefore generates DWL

• A combination of fixed and variable tariffs

can help reduce DWL and increase efficiency

of outcomes

• Pricing Rules adopted by Regulators need to

provide clarity, stability and predictability to

investors/developers;

• Incentive-based regulation reduces

information asymmetry and efficiency

factors set by regulators should be

ambitious but reachable by utilities.

• Stakeholder consultation/counterparty

cooperation important to achieving buy-in

THANK YOU

FOR YOUR ATTENTION!

ERRA Tailor-made Training Course: Principles of Tariff RegulationDecember 2-4, 2018 • Muscat, Oman

Ardian Berisha

E-mail: ardian.berisha@erranet.org

Web: www.erranet.org

Economics of Price Regulation - ERRA€¦ · ERRA Tailor-made Training Course: Principles of Tariff...

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