overview of proposed guidelines · overview of proposed guidelines. coverage of this presentation...

25 August 2016

Kasetsart UniversityEnergy Engineering Institute

In association with

Gas Tariff ReviewOverview of Proposed Guidelines

Coverage of this presentation

Licensees

Natural Gas Transmission (PTT-GTM unit)

LNG Terminal (PTT-LNG)

Natural Gas Wholesale (currently, only PTT-GSM unit)

Natural Gas Retail (PTT-NGR unit, PTT NGD, Amata NGD)

Topics

Overview of the current (2007) natural gas tariff Guidelines

Reasons for changes to the current Guidelines

Summary of the proposed new Guidelines

2

1. Natural Gas Transmission

2. LNG Terminal

3. Natural Gas Wholesale

4. Natural Gas Retail

5. Summary

1. NATURAL GAS TRANSMISSION

Overview of 2007 Guidelines

Transmission demand charge (Td)

Costs recovered

Costs of financing investments and fixed O&M costs

Calculation methodology

Uses a discounted cash flow (DCF) methodology

The calculation is carried out for the remaining lifetime of the assets

Frequency of calculation

Recalculated at 5-year intervals to incorporate changes in volume

projections and to roll-in new investments

Interim adjustments can be made for large changes in asset values,

volumes or gas specifications

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Td = NPV [(Investment - Loans) + (Loan repayment + Fixed O&M + Interest + Tax)]

NPV(Planed volumes)

Discount rate = Return on equity

The Guidelines specify for each pipeline, the values used for calculation are

Return on equity

Loan term (years)

Interest rate

Debt-to-Equity ratio

Fixed O&M allowance (set at 3% of capital expenditure)


Discounted cash flow calculation methodology

5


Transmission commodity charge (Tc)

Costs recovered

Variable costs and costs of fuel used in compressors


Actual values from the previous year updated for changes in input prices

and efficiency improvements

Frequency of calculation

Calculated annually

6

XWP

WPX

CPI

CPI

Q

VCTc

t

t

t

t

t

t

t

12

1

1

1 88.012.0

The current guidelines fix key inputs to the calculation of the demand

charge

As a result, over time, prices move out of line with costs with increased

risks to licensees and to customers

These mismatches are particularly noticeable with respect to the allowed

cost of capital (return on equity and debt service costs)

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Reasons for change

Mismatches between current and allowed costs

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Reasons for change

Allowed financing costs have not adjusted over time

9

Australia WACC decisions

Reasons for change

Best practice is for the cost of capital to track market rates

Ireland WACC decisions

Proposed new Guidelines

Replace DCF with a building-block calculation

Input values will be reset at 5-year intervals and allowed revenues and

demand charges will be calculated for 5-years at a time using the new

input values

A single weighted average cost of capital (WACC) reflecting current

financial market conditions will be set for all PTT-GTM’s assets at each 5-

year interval

The debt service allowance used in the DCF calculation will be replaced

with a depreciation allowance with interest costs being recovered through

the WACC allowance

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- 11 -

Return

Fixed Opex

Depreciation

Tax

RAB * WACC

Fixed O&M

RAB / asset

life

Corporate tax

Allowed Revenues

Sums to

Quantities

Tariffs

Td = PV (allowed revenues) / PV (volumes)

Present values are calculated over a 5-year

period using WACC as the discount rate


The building-block methodology illustrated

WACC Weighted Average Cost of Capital

RAB Regulated Asset Base


Other elements of the demand charge calculation

Interim adjustments within each 5-year period are allowed where there are

major differences (>20%) between

Actual costs and allowed revenues used to calculate charges

Actual volumes and projected volumes used to calculate charges

Multiple transmission zones can be used for charging purposes, as under

the 2007 Guidelines. The licensee proposes the boundaries of each zone

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Incentives for efficiency improvements

Financing costs

WACC is reset at 5-year intervals based on estimates of financing costs

under current market conditions

If licensees can reduce actual financing costs below WACC then they are

able to keep the resulting savings

WACC at the next reset is then calculated using the new, lower costs

Fixed O&M costs

Controllable O&M costs are projected using a CPI – X formula

Base O&M costs are reset at 5-year intervals based on actual costs

13


Calculation of commodity charges

The methodology in the 2007 Guidelines is retained

ERC will have discretion to adjust the weights applied to CPI, gas and

electricity prices in the calculation, based on historic shares in total costs

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2. LNG Terminal



5. Summary

2. LNG TERMINAL


Demand and commodity charges (Ld and Lc)

Approach

The calculation of LNG terminal charges is specified in the 2011

Guidelines

The current arrangements apply the same methodology as for natural gas

transmission charges


Demand charges are calculated for the lifetime of the terminal using the

same DCF methodology as for natural gas transmission

The projected volumes of LNG sent out used in the DCF calculation are

those included in the NEPC-approved investment proposal

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The calculation of LNG terminal charges has the same weaknesses as for

natural gas transmission charges

Mismatches between current and allowed costs, due to the failure to update

input values

Limited incentives for efficiency improvements by licensees

In addition, the use of projected volumes at the time of investment approval

to set demand charges places the licensee at risk if actual utilization is less

than these levels

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Reasons for change

Mismatches, limited efficiency incentives and high risks

Current LNG terminal utilization is below the projected levels at the time

of investment approval

Under existing arrangements, PTT LNG’s demand charge is calculated

using these projected volumes rather than actual volumes

This leaves PTT LNG at risk of under-recovering the costs of its

investments

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Reasons for change

PTT LNG’s volume risk


Adopt a building-block calculation

LNG terminal charges will be calculated using the same building-block

methodology as for natural gas transmission

Input values will be reset at 5-year intervals and allowed revenues and

demand charges will be calculated for 5-years at a time

Fixed O&M costs will be projected including an efficiency (X) factor

Commodity charges will continue to be calculated annually by concern of

efficiency and cost price change.

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2. LNG Terminal



5. Summary

3. NATURAL GAS WHOLESALE


Wholesale margin calculation

EGAT / IPP

1.75% of average gas price

Capped at 2.1525 THB/mmbtu (equivalent to 1% of current pool gas price)

SPP

9.33% of average gas price

Capped at 11.4759 Bt/MMBTU (equivalent to 5.7% of current pool gas

price)

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NEPC meeting #2/2554 (23 February 2554) determined that the wholesale

gas price will, in future, be calculated as

P = WH + (S1 + S2) + T

S1 Cost for the supply and wholesale of natural gas including

remuneration

S2 Risk to guarantee the quality and security of supply of natural gas and

other risks

The detailed calculation of S1 and S2 is to be defined under guidelines to

be issued by ERC

Reasons for change

NEPC decision on wholesale margins

22

ERC may determine that there is

no requirement for advance

approval of the tariffs charged by

a wholesaler where

the wholesale market is

competitive

the individual wholesaler does not

have a dominant position

ERC will continue to monitor

wholesale tariffs, even where not

approving these

Two-step test of the need for

regulation

• Is there competition in the market?

• Does an individual licensee have a

dominant position (requiring

regulation)?


Test whether regulation is needed

Cost remuneration component (S1)

A1 margin recovers ‘normal’ costs including working capital, bad debts and the

retailer’s profits

A2 recovers additional ERC-approved costs (eg, compensation payments)

Compensation for risks component (S2)

Recovers costs of additional risks that are not included in the S1 component

Can differ by customer type

- 24 -

A1Operating

costs

A2Approved

costs

Risk 1?Approved

costs

Risk 2?Approved

costs

Risk 3?Approved

costs

Risk 4?Approved

costs

S1Recovery of licensee’s costs

S2 Compensation for additional supplier risks


Components of the regulated wholesale margin


Calculation of the S1 component

A1: Recovery of normal costs

Set by benchmarking against comparator utilities

We propose that A1 is approved as a % of the wholesale price and

converted into THB/MMBTU by multiplying by the pool price in each month

Many of the costs included under A1, such as working capital and bad debts,

will change as the wholesale price changes

Alternatively, A1 can be expressed in THB/MMBTU and indexed to changes in

the wholesale price

A2: Other ERC-approved costs

Includes license fees, approved compensation payments (including for

changing gas quality) and any other ERC-approved costs

A2 is expressed in THB/MMBTU

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The wholesaler proposes the

costs of a additional risk to be

included in the S2 component

ERC reviews and determines

Whether a additional risk exists

What are the costs of a additional

risk to the wholesaler

Potential risks are discussed on

the next slide

Process to include additional risk

into the margin

• Provide a definition of the additional risk to

which the proposed cost allowance

relates.

• Provide evidence that the additional risk

exists.

• Provide a proposed methodology for

calculating the costs of the additional risk.

• Provide the assumptions and input data to

be used in the calculation.

• Provide a comparison of the estimated

costs of risk for the forthcoming tariff

control period with historical costs related

to the same risk.

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Calculation of the S2 component


Potential additional risks

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Customer Switching Risk

Customers fail to take full volumes (eg, because they switch to another wholesaler) leaving the

wholesaler with excess contracted supplies

Forecasting Risk

Wholesaler is required to sign long-term take-or-pay contracts to meet forecast demand (eg,

under PDP) and takes risk that actual demand is below forecast

Interruption Risk

Wholesaler is required to compensate customers for the costs of upstream interruptions in

supply that are outside the wholesaler’s control

Example available additional risk


Potential additional risks

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Gas Quality Risk

Wholesaler is required to compensate customers for the costs of adjusting and replacing

equipment as gas specifications change

Pipeline Capacity Booking Risk

For customers with volatile demand, the wholesaler is required to reserve pipeline capacity to

meet the potential maximum when actual demand is often below this

Additional Customer Default Risk

Individual customer types have a higher (or lower) risk of default or late payment than the

average risk recovered through the remuneration charge (A1 component)

Example available additional risk


2. LNG Terminal



5. Summary

4. NATURAL GAS RETAIL


Retail prices are indexed to fuel oil prices

Indexed to fuel oil price (Mean of

Platts Singapore)

Indexation values rise as fuel oil

price rises…

…but can fall dramatically if crude

oil price collapses

The intent is to ensure natural gas

remains competitive against

alternative fuels

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Fuel oil and industrial gas price

0

100

200

300

400

500

600

700

2008 2009 2010 2011 2012 2013 2014 2015

TH

B/m

mb

tu

Fuel Oil PTT NGR

Reasons for change

Retail tariffs do not track costs, leading to excess margins

A combination of high oil prices

and low-cost gas supplies have

enabled PTT-NGR to earn very

high margins in recent years

These margins greatly exceed our

estimates of the costs of gas

retailing

However, PTT-NGR’s margins

have recently fallen to near-zero

levels

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Source: Consultants estimates

In principle, licensees high margins in some years should be offset by low

or negative margins when oil prices fall—thus ensuring that gas remains

competitive and sharing risk between licensees and its customers

However, it is not sustainable for licensees to make losses on gas retail for

extended periods. Indeed, licensees is proposing changes to the

indexation formula to restore its margins going forward

This undermines the argument for linking to oil prices—customers pay a

high gas price when oil prices are high but don’t see gas prices fall when

oil prices reduce

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Reasons for change

Indexation does not work as intended


Options for future retail pricing methodologies

Retain the current indexation methodology

We have previously identified our concerns with this methodology

Retain indexation but introduce a floor and ceiling

A floor is used to protect licensees again the impacts of low oil prices

In the interests of fairness, customers are protected by introducing a ceiling

on gas prices when oil prices are high

Introduce a cost-reflective methodology

Avoids the risk that prices move out of line with costs, thereby protecting

licensees and customers

Leads to more efficient prices and, therefore, investment decisions

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Our concerns with a floor and ceiling methodology

Move to a cost-reflective pricing methodology, replacing the current

indexation approach

Pass-through wholesale gas price costs to customers

Separate distribution charges and retail margins are calculated for retail

licensees, recovering distribution network costs and retail supply costs

respectively

Distribution charges and retail margins are calculated separately for each

retail licensee using their individual costs and volumes

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Our proposed approach


Calculation of distribution and retail charges

Distribution charges

Apply a Distribution Demand Charge (Dd) and Distribution Commodity

Charge (Dc)

Charges are calculated using the same methodology as transmission

demand and commodity charges

Charges are recalculated at 5-year intervals

Retail margin

Apply a Retail Margin (M1 + M2)

Margin is calculated using the same methodology as the wholesale margin

Margins are recalculated at 5-year intervals

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2. LNG Terminal



5. Summary

5. SUMMARY


Structure of natural gas prices

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Td + Tctransmission charge

Wx = P + (S1 + S2) + (Td + Tc)

wholesale price

Ppool price

S1 + S2wholesale margin

M1 + M2retail margin

Dd + Dcdistribution charge

Ry = WRetailer + (M1 + M2) + (Dd + Dc)

retail price

Ld + LcLNG terminal charge

Regulated

under

Guidelines

border gas price

wellhead gas

priceLNG import price

x = Customer types EGAT/IPP

SPP

Retailer

y = Licensees PTT-NGR

PTTNGD

AMATANGD


Charging methodologies

Natural gas transmission and LNG terminal

Apply a building block methodology to calculate demand charges

Recalculate input values, allowed revenues and charges at 5-year intervals

Retain existing approach to calculating commodity charges

Natural gas wholesale

Specify calculation of remuneration and compensation components

Natural gas retail

Separate distribution and retail supply costs

Recover through distribution charges calculated as for transmission and

retail margin calculated as for wholesale

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[email protected]

[email protected]

[email protected]

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