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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
4
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)
Overview of 2007 Guidelines
Discounted cash flow calculation methodology
5
Overview of 2007 Guidelines
Transmission commodity charge (Tc)
Costs recovered
Variable costs and costs of fuel used in compressors
Calculation methodology
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)
7
Reasons for change
Mismatches between current and allowed costs
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
10
- 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
Proposed new Guidelines
The building-block methodology illustrated
WACC Weighted Average Cost of Capital
RAB Regulated Asset Base
Proposed new Guidelines
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
12
Proposed new Guidelines
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
Proposed new Guidelines
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
14
1. Natural Gas Transmission
2. LNG Terminal
3. Natural Gas Wholesale
4. Natural Gas Retail
5. Summary
2. LNG TERMINAL
Overview of 2011 Guidelines
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
Calculation methodology
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
16
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
17
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
18
Reasons for change
PTT LNG’s volume risk
Proposed new Guidelines
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.
19
1. Natural Gas Transmission
2. LNG Terminal
3. Natural Gas Wholesale
4. Natural Gas Retail
5. Summary
3. NATURAL GAS WHOLESALE
Overview of 2007 Guidelines
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)
21
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)?
Proposed new Guidelines
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
Proposed new Guidelines
Components of the regulated wholesale margin
Proposed new Guidelines
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
25
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.
26
Proposed new Guidelines
Calculation of the S2 component
Proposed new Guidelines
Potential additional risks
27
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
Proposed new Guidelines
Potential additional risks
28
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
1. Natural Gas Transmission
2. LNG Terminal
3. Natural Gas Wholesale
4. Natural Gas Retail
5. Summary
4. NATURAL GAS RETAIL
Overview of 2007 Guidelines
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
30
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
31
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
32
Reasons for change
Indexation does not work as intended
Proposed new Guidelines
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
33
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
35
Proposed new Guidelines
Our proposed approach
Proposed new Guidelines
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
36
1. Natural Gas Transmission
2. LNG Terminal
3. Natural Gas Wholesale
4. Natural Gas Retail
5. Summary
5. SUMMARY
Proposed new Guidelines
Structure of natural gas prices
38
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
Proposed new Guidelines
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
39