Assessment of Requirement for Gas
Contingency Service Obligations
Final Report to the Public Utilities Office
May 2015
Synergies Economic Consulting Pty Ltd
www.synergies.com.au
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Executive Summary
This report assesses the economic case for implementing Gas Contingency Service
Obligations (GCSOs) on gas retailers. Such a measure, if implemented, would be
designed to ensure that retailers have the capacity to maintain supply to small-use
customers in the event of a gas supply disruption caused by physical failure of a gas
processing plant or the Dampier to Bunbury Natural Gas Pipeline (DBNGP).
While the stated policy objective of a GCSO is to maintain security of supply to smalluse customers, these customers are unlikely to gain any additional benefits from a
GCSO in terms of increased reliability of gas supply. This is principally because there
are practical and cost barriers to discontinuing supply to small-use customers
(requiring closing of gas valves at individual premises).
The potential benefit of a GCSO is therefore related to possible cost-efficiency
improvements in the way retailers manage the risk of a disruption event in terms of
securing additional gas or curtailing demand. This economic benefit is analogous to
taking out insurance against a specified risk (i.e. paying an annual insurance premium
to reduce the lump sum cost imposed by a highly uncertain major event).
In the context of gas supply, insurance may take the form of physical supply buffers,
taking forward positions in the gas market or having strategies and plans in place so as
to maintain a state of readiness should an event occur.
Approach
This study involved extensive consultation with stakeholders, desktop research and
economic modelling. Synergies also drew on technical risk modelling undertaken by
Advisian, who were engaged as technical consultants to the study.
It is difficult to be definitive about whether retailers are currently using the least cost
(optimal) mix of options for managing disruption risk because retailers were unwilling
to disclose specific details about supply contracts and how they balanced customer
demand against available supply through fuel switching and the like. Nor could we
determine an estimate of the cost of contingency currently held by each retailer.
However, by modelling the costs of each option as a stand-alone measure it was
possible to develop an understanding of the magnitude of cost involved in taking preemptive action through adoption of one or more mitigation measures, relative to the
cost of responding to disruption events when and if they occur.
Page 3 of 60
M odelling m ethod and assum ptions
A Cost Effectiveness Analysis (CEA) framework is applied to assess the costs of
different contingency options for maintaining a continuous supply of gas to small use
customers under a range of disruption scenarios (four scenarios were examined). The
purpose of CEA is to identify the option that will result in the policy objective being
achieved at lowest cost.
The contingency options assessed are:
•
Storage of gas in the Mondarra Gas Storage Facility
•
Insuring against future supply risk through the use of options contracts
•
Buying gas on the short term market, when and if the disruption occurs
•
Curtailing gas to large gas users, when and if the disruption occurs
•
Switching to alternative fuels to power electricity generation (in those cases where
a retailer also operates generation facilities as part of its business)
The first two of these options are pre-emptive, while the remaining three are re-active
strategies.
A key input for the economic analysis is the volume of unmet demand (or shortfall)
experienced by retailers in serving their customers in the event that a disruption occurs
(and that no forward contingency measures are in place). This information is obtained
from risk modelling undertaken by Advisian, the technical consultants to the study.
The risk modelling produces estimates of gas shortfall (TJ/d) and probability of a
specified disruption scenario.
Costs are assessed over a 30 year timeframe. It is standard practice to use a timeframe
of between 20 and 30 years when assessing the benefits of an insurance policy, which
involves up-front and recurrent costs, but will only yield a pay off on a periodic basis.
The annual costs incurred over the entire period of the analysis are discounted to a Net
Present Value (NPV), which allows for valid comparison of options involving up-front
costs (Mondarra storage or the purchase of options contracts) to those that do not
involve up-front costs.
Key results
The key findings of this analysis are as follows:
Page 4 of 60
•
Mondarra storage is a considerably more expensive option for maintaining gas
supply to small use customers than the other four options.
•
Short term trading, closely followed by curtailment of gas to large customers, are
the cheapest options for managing a disruption under scenario 1 (failure of the
Karatha Gas Plant for three months with a loss of 600TJ per day).
•
Under scenarios 3 and 4 (rupture of the DBNGP for 7 days, north or south of
Mondarra respectively) the only contingency options that are technically feasible
are curtailment of large users, fuel switching, and Mondarra storage. 1 The results
demonstrate that curtailment and fuel switching are the cheapest options by a
large margin. This is attributable to:
−
the relatively low cost of obtaining sufficient volumes of gas through these
measures at the time of an incident to meet small use demand ($13 million for
curtailment or $15 million for fuel switching under a scenario 3 disruption in
a period of peak demand);
−
the very low assumed probability of a rupture to the DBNGP (once in every
300 to 600 years); and
−
the fact that the Mondarra option involves payment of a fixed storage fee of
$8 million each year to insure against a potential (low probability) loss of
supply to small use customers that would cost, at most, $15 million to
mitigate through fuel switching or curtailment in the year that it occurred.
These findings hold over a wide range of assumed values for model parameters.
Conclusion
There are significantly cheaper options available than using Mondarra storage as a
contingency measure for mitigating the risk of a gas plant failure. While curtailment of
gas to large users remains an option for responding to this risk, the majority of
stakeholders consulted in the course of this study indicated that retailers would action
other options ahead of curtailment if possible. The availability of diverse sources of gas
supply at relatively low prices (compared to several years ago) means that sourcing
additional supply on the market or through pre-existing options contracts would be
utilised by retailers ahead of curtailment.
If the DBNGP was to rupture in an unlooped section, this would represent a more
severe disruption because it would prevent the flow of gas from the major production
1
Mondarra is unlikely to be technically feasible under scenario 4 due to pipeline capacity constraints in accessing the
gas, however cost estimates are presented for comparative purposes.
2
A small-use customer is defined at section 3(1) of the Energy Coordination Act 1994 as a residential or small business
Page 5 of 60
plants in the north to areas of demand in the south. Faced with this scenario, retailers
would have limited options available. Based on Advisian’s modelling, we estimate that
up to 55 TJ/d would need to be ‘found’ in the system to maintain gas supply to small
use customers. This amount of gas could be obtained through curtailing all large
customers and/or switching electricity generators to alternative fuel sources. This
would cost up to $15 million in the year of the incident. However, as the probability of
pipeline failure is estimated to be very low (just 1 in 300 to 600 years), this cost reduces
to just $0.44 million in probability-weighted NPV terms (over a 30 year timeframe).
This makes the annual cost of reserving capacity in Mondarra ($8 million per year)
prohibitively expensive as a risk mitigation measure, as it would be a cost that would
be incurred irrespective of whether an incident occurs or not. When this cost is
aggregated over a 30 year timeframe the cost becomes $107 million in NPV terms.
It is concluded that there is no economic case for a CGSO because the gas requirements
of small use customers can be maintained at relatively low cost by responding to an
event when, and if, it happens. Further, it is evident that retailers are currently hedging
some of their risk exposure through contractual means and, given the relatively small
volumes of gas that would need to be found to maintain small use customer demand,
there would be minimal, if any, economic benefit from requiring retailers to adhere to a
mandatory contingency service obligation.
Page 6 of 60
Contents
Executive Summary
3!
1! Introduction
9!
1.1! Background
9!
1.2! Project objectives
9!
1.3! Organisation of this report
2! Overview of approach
11!
13!
2.1! Cost-effectiveness analysis
13!
2.2! Stakeholder consultation
14!
3! Nature of the supply disruption risk
16!
3.1! Supply disruption scenarios
16!
3.2! Capacity of the market to respond to disruption
17!
3.3! Potential options available to retailers to manage supply risk
25!
3.4! Contingency arrangements currently held by retailers
26!
4! Modelling method and assumptions
30!
4.1! Overview of modelling steps
30!
4.2! Input assumptions
33!
5! Model results
43!
5.1! Comparative analysis of contingency options
43!
5.2! Cost breakdown for the Mondarra storage option
46!
5.3! Cost of contingency options relative to Mondarra storage
47!
5.4! Sensitivity analysis
48!
6! Conclusion
52!
A! List of stakeholders consulted
55!
B! Summary of consultation findings
56!
C! Cost of curtailment estimation method
59!
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Figures and Tables
Figure 1! Daily production volumes and capacities by domestic gas producers (TJ per
day)
19!
Figure 2! Modelling steps
30!
Figure 3! Total shortfall to small-use customer supply by disruption scenario (TJ)
37!
Figure C.1 Graphical representation of welfare loss through curtailment of gas supply60!
Table 1! Technical feasibility of options for each supply disruption scenario
33!
Table 2 ! Likelihood of supply disruption scenarios
35!
Table 3 ! Residual supply shortfalls under each disruption scenario
36!
Table 4 ! Total supply shortfalls under supply disruption scenarios
37!
Table 5 ! Incremental cost of sourcing lost gas volumes through short-term trading 38!
Table 6 ! Estimated cost of contingency options for mitigating supply disruptions to
small use customers (assuming the disruption occurs in 2015/16)
43!
Table 7 ! Summary of cost estimates by contingency option and scenario (NPVs)
45!
Table 8 ! Cost of storing contingency supply in the Mondarra storage facility (NPV
terms)
47!
Table 9 ! Cost of options relative to Mondarra storage
48!
Table 10 ! Sensitivity analysis results
49!
Table 11 Required frequency of disruption events to equalise the cost of Mondarra to
other contingency options
50!
Table B.1 ! Summary of key themes emerging from stakeholder consultations
56!
Page 8 of 60
1
Introduction
1.1
Background
In 2008, two major gas supply disruptions resulted in a significant supply shortfall in
the Western Australian gas market and imposed significant costs on gas users. The
Western Australian Government responded by establishing the Gas Supply and
Emergency Management Committee (GSEMC) and tasked it with reviewing the
security of Western Australia’s gas supplies and assessing how future supply
disruptions should be managed.
The GSEMC’s report included several recommendations, one of which was to require
gas retailers to have adequate back-up supply arrangements to ensure continuity of
supply for small-use customers. 2 This recommendation was based on an assessment
that gas retailers, and the domestic gas market more broadly, were inadequately
prepared to respond to major gas supply disruptions and as a consequence inefficient
costs were being incurred. However, a subsequent analysis by PwC3 concluded that
the cost of implementing mandatory, pre-emptive mitigation measures to maintain
supply to small use customers would be inefficient because it would be cheaper to
respond to the supply disruption when, and if, the disruption occurs – even after
allowing for costs imposed by shortfalls in supply. This finding was based on
information available at the time on the cost of gas storage, which was assumed to be
the main contingency measure.
1.2
Project objectives
The Public Utilities Office (PUO) has engaged Synergies Economic Consulting
(Synergies) to undertake a robust analysis of the implementation of mandatory Gas
Contingency Service Obligations (GCSOs) to ensure that gas retailers have the capacity
to maintain supply to small-use customers in the event of a gas supply disruption.
While the stated policy objective of a GCSO is to maintain security of supply to smalluse customers, these customers are unlikely to gain any additional benefits from a
GCSO in terms of increased reliability of gas supply, as supply is unlikely to be
threatened by a disruption event within the range of scenarios under consideration in
this study. This is due to the following factors:
2
A small-use customer is defined at section 3(1) of the Energy Coordination Act 1994 as a residential or small business
customer that consumes less than 1 TJ of gas per year.
3
PwC (2010) Review of options for implementing electricity and gas market contingency arrangements. A report to the Office
of Energy.
Page 9 of 60
•
There are practical and cost barriers to discontinuing supply to small-use
customers (requiring closing of gas valves at individual premises);
•
the engineering issues (and costs) associated with the depressurisation of the
reticulated gas distribution network in the event that supply is discontinued; 4
and
•
the provisions in the Westplan for Gas Supply Distribution,5 which allocate priority
of supply to small-use gas customers in the event of a major supply disruption.
These factors result in gas retailers already having an implied obligation to maintain
gas supply to small-use customers in the event of a major supply disruption.
The potential benefit of a GCSO is therefore related to possible cost-efficiency
improvements in the way retailers manage the risk of a disruption event in terms of
securing additional gas or curtailing demand. This economic benefit is analogous to
taking out insurance against a specified risk (i.e. paying an annual insurance premium
to reduce the lump sum cost imposed by a highly uncertain major event). In the context
of gas supply, insurance may take the form of:
•
physical supply buffers, for example storage of gas for future use, or accessing
linepack ;
•
taking forward positions in the gas market – for example, options contracts with
multiple gas suppliers or large users that may be wiling to sell gas to a retailer in
the event of a disruption; and
•
having strategies and plans in place so as to maintain a state of readiness should
an event occur.
There are two possible reasons why retailers may not be optimally managing their risk
from an economic efficiency perspective. First, when confronted by a supply
disruption a retailer may act to call force majeure on its contracts with large customers
as a means of maintaining supply to small use customers. This imposes costs on large
customers that are not compensated for by the retailer. In effect, it is an externality cost
of assigning priority supply to small use customers. Second, retailers may not have
sufficient incentives to minimise their costs of responding to a disruption if they can
pass costs through to customers as tariff increases without recourse or regulatory
4
Depressurisation can occur if gas output is greater than gas input into the network. Once depressurised, a timeconsuming process is required before gas supply can be returned to customers, which can significantly extend the
duration of the supply disruption.
5
This plan details the strategic arrangements for the management of gas supply disruptions, including with respect
to small-use gas customers.
Page 10 of 60
scrutiny. These risks are greatest in circumstances where there is limited retail
competition.
While there may be scope for retailers to depart from an optimal risk management
strategy, the question for this study is whether the incentives to behave in this way are
sufficiently material to justify intervention by government in the form of a mandatory
GCSO. In order to answer this question, it is necessary to address a number of related
questions:
•
what is the nature of the supply disruption risk in terms of likely incidence and
economic cost of responding to a disruption caused by physical failure of the
pipeline or gas production facilities?
•
how has the gas supply chain and market arrangements changed since 2009, and
has this lessened the economic costs and risk of a disruption?
•
what strategies are retailers currently using to manage the risk of major
disruptions?
•
do these current strategies represent a cost effective and efficient means of
maintaining supply to small use customers or would there be a net economic
benefit from imposing a GCSO?
The scope of this analysis is limited to assessing the net economic impact of a GCSO in
the context of maintaining continuous supply to small-use gas customers. Although
gas supply disruptions also have the potential to affect electricity generators and endusers (as a supply disruption could restrict gas supply to gas-fired electricity
generators) and larger gas customers (which can be curtailed in the event of a supply
disruption), the impact of a GCSO on these customer segments is outside the Terms of
Reference for this report.
1.3
Organisation of this report
The rest of this report is structured as follows:
•
section 2 provides an overview of the approach to the analysis;
•
section 3 describes the nature of the supply disruption risk, the capacity of the
Western Australian gas market and supply chain to respond to supply
disruptions, and the strategies currently used by gas retailers to manage this risk;
•
section 4 sets out the economic modelling method and assumptions, including the
key inputs and parameter values applied in conducting the analysis;
Page 11 of 60
•
section 5 summarises the results of the modelling, including the outcomes from
sensitivity analysis performed on key parameters; and
•
section 6 concludes the report.
There are three attachments. Attachment A contains the list of stakeholders consulted
by Synergies between 26 March and 15 April 2015. Attachment B contains a summary
of key themes discussed and raised in consultations with stakeholders. Attachment C
sets out the method used to estimate gas curtailment costs to large commercial and
industrial users.
Page 12 of 60
2
Overview of approach
A high-level overview of the approach used to perform the economic analysis of
alternative contingency and response options is set out in this chapter.
2.1
Cost-effectiveness analysis
A Cost Effectiveness Analysis (CEA) framework is applied to assess the costs of
different options for maintaining a continuous supply of gas to small use customers
under a range of disruption scenarios. The purpose of CEA is to identify the option
that will result in the policy objective being achieved at lowest cost.
Two of these options represent possible contingency measures that may form the basis
of a GCSO, being:
•
a mandatory requirement for retailers to store gas in the Mondarra Gas Storage
Facility; and
•
a mandatory requirement for retailers to hold a sufficient portfolio of options
contracts with a diversity of suppliers and/or existing users to insure against the
risk of a disruption event affecting any one supplier. In this assessment the
options contracts are assumed to offset the risk of a retailer not being able to meet
residual shortfalls in supply after exhausting potential sources of gas that could be
acquired through utilisation of spare production capacity when, and if, a
disruption occurred.
The cost of these options is assessed as the cost incurred in securing an amount of gas
needed in advance (through either options contracts or storage) to cover any shortfalls
in meeting demand that can be notionally assigned to small use customers (based on a
pro-rata allocation of the aggregate shortfall across all customer types according to
their current gas consumption).
The cost of implementing the contingency options above are then compared to the cost
of alternatives that do not involve adopting a forward contingency measure. The
alternatives examined are:
•
curtailing supply to large use customers;
•
reallocating gas from electricity generation through fuel switching (in those
instances where retailers also generate electricity as part of their business); and
•
purchasing gas on the short term gas market.
Page 13 of 60
These options could all be exercised when, and if, the disruption event occurs and do
not involve costs being incurred until such a time.
Costs are assessed over a 30 year timeframe. It is standard practice to use a timeframe
of between 20 and 30 years when assessing the benefits of an insurance policy, which
involves up-front and recurrent costs, but will only yield a pay off on a periodic basis.
Extending the analysis to 30 years allows for potential benefits in any one year (arising
from having the insurance in place) to be properly accounted for. We have not
modelled beyond 30 years because of the increasing uncertainty about input
parameters and the effect of discounting on cash flows beyond this period.
The annual costs incurred over the entire period of the analysis are discounted to a Net
Present Value (NPV), which allows for valid comparison of options involving up-front
costs (Mondarra storage or the purchase of options contracts) to those that do not
involve up-front costs.
A key input for the economic analysis is the volume of unmet demand (or shortfall)
experienced by retailers in serving their customers in the event that a disruption occurs
(and that no forward contingency measures are in place). This information is obtained
from risk modelling undertaken by Advisian, the technical consultants to the study.
The risk modelling produces estimates of gas shortfall (TJ/d) and probability of a
specified disruption scenario.
2.2
Stakeholder consultation
The project involved an extensive stakeholder consultation process. The stakeholders
consulted included gas retailers, gas producers, pipeline operators, and market
regulators and operators. A full list of the stakeholders that were consulted is provided
in Attachment A.
The objectives of consultation were to:
•
clarify the roles and functions of each stakeholder organisation;
•
identify behavioural responses in the market to gas supply disruptions of varying
severity and duration;
•
understand stakeholders’ views and perspectives on the economic case for a
GCSO; and
•
obtain information to inform specific data inputs to the CEA modelling (e.g. gas
prices, cost of contingency arrangements, cost of sourcing additional gas under
disruption scenarios).
Page 14 of 60
Section 3.4 summarises the views and perspectives of retailers in relation to the risk of
disruptions and current contingency arrangements. A complete summary of key
themes raised by stakeholders is presented in Appendix B.
Page 15 of 60
3
Nature of the supply disruption risk
This section contains a description of the supply disruption scenarios assessed in this
analysis and the risks they present in terms of the capacity of the gas market, and more
specifically retailers, to respond to gas shortages under current contractual
arrangements.
The views and perspectives gathered through stakeholder
consultations are also presented.
3.1
Supply disruption scenarios
Advisian was engaged by the PUO to conduct modelling on the impact of a set of
hypothetical supply disruption scenarios. Based on consultation with stakeholders, the
following scenarios were identified as plausible examples of major gas supply
disruptions:
•
Scenario 1: failure of the Karratha Gas Plant (KGP) for 90 days, leading to a loss of
approximately 600 TJ/day of processing and supply capacity over the period;
•
Scenario 2: failure of the equivalent of half the capacity of the KGP for 180 days,
leading to a loss of approximately 350 TJ/day of processing and supply capacity
over the period;
•
Scenario 3: failure of (an unlooped section of) the Dampier to Bunbury Natural
Gas Pipeline (DBNGP) north of the Mondarra and Parmelia Pipeline
interconnections with the DBNGP, with an interruption to gas transmission of
seven days; and
•
Scenario 4: failure of (an unlooped section of) the DBNGP south of the Mondarra
and Parmelia Pipeline interconnections with the DBNGP (that is, between
compressor stations 9 and 10 in the Perth metropolitan area), with an interruption
to gas transmission of seven days.
These four scenarios are the same as those modelled by Evans and Peck (now
Advisian) in 2009 and used by PwC in their 2010 analysis. The pipeline failure
scenarios represent the most severe incidents and would result in emergency measures
to ration gas.
Stakeholders were of a consensus view that these scenarios remain appropriate as
potential risks worthy of examination.
Page 16 of 60
3.2
Capacity of the market to respond to disruption
3.2.1 A historical perspective
At the time of the Varanus Island incident that occurred in 2008, the Western
Australian gas market was highly concentrated on both the supply-side and demandside, with a lack of transparent market information and mechanisms to manage an
emergency supply disruption.
At the time, the domestic market was almost exclusively supplied by three gas
production facilities: two on Varanus Island and one from the North West Shelf Joint
Venture.6 Gas sales from those producers made up 95% of all domestic sales. 7
Furthermore, the two retailers operating in the market at the time each obtained all
their gas requirements from a single source – either Varanus Island or Karratha Gas
Plant (North West Shelf).
The demand-side was characterised by a few large buyers (primarily industrial users
and electricity generators), with relatively inelastic demand (non responsive to price)
due to insufficient flexibility to use alternative fuels.
When gas from Varanus Island was disrupted in 2008, the retailer most affected was
Alinta, as it sourced all its gas from this location. Alinta responded by purchasing
additional quantities of gas from North West Shelf Gas to partially cover gas supply
shortfalls (at prices considerably higher than its existing contract with Apache for
Varanus Island gas) and diverting gas from its electricity generation facilities.
This action enabled gas supply to be maintained to small use customers but it has been
estimated that Alinta incurred a cost of $27.6 million, which was subsequently
recovered through a one-off tariff increase (ex-post) to customers. Small use customers
were allocated $9.3 million of the total cost (which at the time was calculated in
proportion to the level of contracted supplies that were directed towards servicing the
requirements of these customers). 8
In addition to the direct costs incurred by Alinta (and subsequently passed onto
customers), there is some anecdotal evidence to indicate that services to some large
customers were curtailed through a call of force majeure, in order to maintain supply to
6
In 2008 there were two gas production facilities on Varanus Island: the Harriet JV and East Spar JV. Gas from each
JV was processed at one main gas processing plant and transported to mainland via one narrow pipeline corridor,
which consisted of six pipelines.
7
Wood Mackenzie. (2010). Western Australia gas market study – Final Report, 26th March 2010.
8
Western Australian Government, Office of Energy (2010) Gas Tariffs Review Interim Report, March 2010
Page 17 of 60
small-use customers. 9 The costs imposed on large customers from this action were not
compensated.
3.2.2 Developm ents since 2009
A number of developments in the Western Australian gas and electricity markets have
occurred since 2009, which together have contributed to the market being now more
resilient to some forms of supply disruption shocks.
New sources of supply
Three new competing gas suppliers have entered the market since 2011 (Macedon, Red
Gully and Devil Creek). In aggregate these gas production plants have increased the
amount of gas available to the domestic market by 430 TJ per day, 10 which is
approximately 43% of forecast total demand in 2015.11
As at December 2014, the domestic gas market was serviced by eight gas production
facilities with a total production capacity of 1,477 TJ per day.12 This compares to an
average daily demand of 1000 TJ per day.13 The benefit of this surplus capacity, in
terms of providing a buffer against supply disruptions, is demonstrated in Figure 1
overleaf, which shows that when Varanus Island experienced a disruption in January
2015 and another in March 2015 (due to a cyclone), the supply deficit was backfilled by
additional supply brought online from Devil Creek. Each of these events is circled in
red.
The amount of surplus gas capacity in the domestic market will increase further with
the commissioning of Gorgon in mid-2015 (which will deliver an additional 300 TJ over
a number of stages out to 2020, with 182 TJ expected to be delivered in 2015) and
Wheatstone in 2018 (which is expected to supply 200 TJ to the domestic gas market).14
Thus, an additional 500 TJ will become available over the next five years or so.
9
PwC (2010) Review of options for implementing electricity and gas market contingency arrangements. A report to the Office
of Energy
10
Independent Market Operator (2014) Gas Statement of Opportunities – December 2014, pp. 39-40.
11
NIEIR forecasts 2015-2024. Adapted from: IMO. (2014). Gas Statement of Opportunities – December 2014, p. 9, 81.
12
Independent Market Operator (2014) Gas Statement of Opportunities – December 2014.
13
ibid
14
DomGas Alliance (2013) WA Domestic Gas Market Outlook, Final, February 2013
Page 18 of 60
Figure 1 Daily production volumes and capacities by domestic gas producers (TJ per
day)
!
Note: The horizontal blocks in this figure represent the nameplate capacity of each production facility (in TJ per day) and is plotted
against the left hand axis. Total capacity adds to 1477 TJ/d. Actual daily production from each facility is shown as an overlay within each
block corresponding the relevant facility. The charts within each block should be viewed as separable, each having a horizontal axis set
at zero TJ/day. Total gas supplied to the domestic market (the sum of production from all six producers) is indicated by the line in black.
Data source: Gas Bulletin Board (2015).
Increased pipeline capacity and looping
Since 2008, the Dampier to Bunbury Natural Gas Pipeline (DBNGP) has undergone
two stages of expansion, which has increased pipeline capacity to 845TJ per day.
Approximately 83% of the DBNGP is now looped, effectively creating a second
pipeline parallel to the existing asset.15 Compressor stations, control and
communications systems and metering equipment on the pipeline were also upgraded
as part of the expansions.
The DBNGP has surplus capacity to accommodate the shipping of additional gas. The
Independent Market Operator (IMO) estimates that as of June 2015, around 89.5% of
DBNGP’s full-haul nameplate capacity will be fully contracted. However, only 76% of
the pipeline’s capacity was actually utilised during 2013-14.16 Comparing contracted
capacity with historical utilisation rates indicate that there is a sufficient capacity buffer
in the DBNGP to accommodate fluctuations in gas demand and supply.
15
http://www.dbp.net.au/the-pipeline/pipeline-history/
16
IMO (2014) Gas Statement of Opportunities – December 2014, p. 139.
Page 19 of 60
Gas storage
The Mondarra Gas Storage Facility (Mondarra), which is owned and operated by APA
Group, was completed in 2013. It is an underground reservoir that has a storage
capacity of 15PJ and is available as a multi-user gas storage facility.17 Mondarra is
situated at the north end of the Parmelia Pipeline and is interconnected with sections of
the DBNGP that connects to the north end of the ATCO Gas Australia’s mid west and
south west gas distribution system. The facility enables gas users to inject gas from the
DBNGP, store it for a period of time, then withdraw it and ship it south to Perth using
either the DBNGP or the Parmelia Pipeline.
The Mondarra facility has an injection capacity of 70 TJ per day and a withdrawal
capacity of 150 TJ per day. Electricity generator and gas retailer, Synergy, has a
foundation contract with APA Group to store gas in the facility equivalent to 30 days
of supply at a withdrawal rate of 90 TJ per day.
The ability to store gas in Mondarra provides gas retailers with another option for
managing their supply risk under particular disruption scenarios (see chapter 4 for
details).
DBP, the operator of the DBNGP, offer a “storage banking” or “park and loan” service
for gas shippers. This offers the flexibility for gas shippers to park excess gas
production within the pipeline or to withdraw gas from the pipeline to meet shortfalls.
There are 20 shippers on the DBNGP that can park and loan from the pipeline on any
day of +/-8% of their contracted capacity.18 A shipper has the option to trade with
other shippers if it perceives itself as likely to break the +/-8% limits. This provision
enables increased flexibility in the way pipeline capacity is utilised, but unlike
Mondarra it does not offer gas users a large facility for storing gas for major supply
disruptions.
Flexible contracts
Gas produced is Western Australia is mainly sold through medium-to-long-term
contracts. The IMO estimates that around 98% of gas traded is done so under long term
bilateral contracts. 19 Many of these long term contracts are with the North West Shelf
and Varanus Island.
17
While Mondarra has an advertised storage capacity of 15PJ (see APA Group, Mondarra Gas Storage Facility Fact
Sheet), not all of this gas is available as working gas. The technical consultants used by the PUO for this study
(Advisian), have used 5 PJ as an indicative volume of working gas for the purposes of modeling disruption
scenarios.
18
Domgas Alliance. (2010). North West Shelf Joint selling authorisation – appendix to submission to the ACCC, 30
April 2010. See; http://www.domgas.com.au/reports_submissions.html.
19
WA Independent Market Operator. (2014). Gas Statement of Opportunities – January 2014.
Page 20 of 60
It is estimated that there are at least 60 active bilateral gas supply agreements20
between gas producers and gas buyers in WA. This estimate takes into account
multiple contracts that are entered into between a single gas consumer and multiple
producers.
Most of the existing long term contracts are relatively inflexible as they are ‘take or
pay’ contracts that require the buyer to take delivery of a minimum quantity or pay for
it in any event. In recent years however there has been an emergence of gas being
offered on more flexible terms by sellers, primarily because of the surplus capacity in
the market. This includes flexibility with respect to the ability to renegotiate prices to
reflect changing market conditions, flexibility with respect to volume, and the
provision for options to purchase a specified volume of gas in a future period at an
agreed price. These developments provide gas retailers with another means of hedging
supply risk caused by a potential disruption.
There has also been an increase in the use of short-term contracts. While still
representing only a small proportion of the market by volume, short term contracts are
being increasingly used by gas retailers and large users as a means of balancing shortterm requirements for gas.21
Short-term trading of gas is facilitated through one of the following methods:22
•
bilateral contracts that involve two market participants directly contracting with
each other; or
•
through energy trading platforms such as the platform managed by Energy Access
Services Pty Ltd and gasTrading23.
Trading platforms
There are now two trading platforms in Western Australia that offer market
participants the ability to manage spot and short-term to medium-term gas
requirements.
20
IMO. (2014). Gas Statement of Opportunities – January 2014, p. 34.
21
Data provided by gasTrading to the Independent Market Operator shows that short-term trades via its platform has
increased from an average of approximately 5 TJ per day to 15 TJ per day over the January 2012 to October 2013
period. See; IMO. (2014). Gas Statement of Opportunities – December 2014, p. 105.
22
WA Independent Market Operator. (2014). Western Australia’s gas services: information – a step towards a
transparent and liquid future for domestic gas markets, a presentation for the Australian Domestic Gas Outlook,
February 2014.
23
Approximately 6-10 TJ per day or 1% of total quantities are traded on the gasTrading spot market. See; IMO. (2014).
Gas Statement of Opportunities – December 2014, pp. 36-37.
Page 21 of 60
Energy Access Services operates an Energy Trading Platform that enables short-term
(up to seven days) and medium term (up to 90 days) to all gas buyers and sellers of gas
in WA along any major gas transmission pipeline. Contracts agreed on the Energy
Trading Platform are standardised. Spot trading opportunity is available through
gasTrading, which was established in mid-2009. Almost every gas shipper on the major
pipelines uses gasTrading to arrange for delivery of gas within the network.24
Capacity to fuel switch
Since 2009 there have been significant changes to the electricity generator sector’s
demand for gas. Considerable investment has been made in upgrading the South West
Interconnected System (SWIS), which has reduced the network’s reliance on gas and
increased its overall baseload capacity.25 Improvement in technology and availability of
renewable energy (i.e. solar and windfarm generation) to the electricity network has
changed the generation mix in the SWIS. In 2013, coal accounted for half of the
electricity generated in the SWIS, followed by gas (35%), renewable energy (9%), and
dual-fuel and diesel facilities (6%).26 Compared to the energy generation mix in 2007,
six years later in 2013 the amount of electricity generated from renewable sources had
doubled, generation from gas had decreased by 10% and generation from coal had
increased by 30%.27
Overall, the Wholesale Electricity Market now has significant generation capacity
surplus to electricity requirements.28 This implies that compared to 2008, there is now
greater flexibility in the system to divert gas from electricity generation to meet the
needs of other gas users.
Market arrangements
The Gas Supply and Emergency Management Committee (GSEMC) was established in
2009 to advise on options for managing supply security and mitigate supply
disruptions. As a result, the Gas Bulletin Board (GBB) and the Gas Statement of
Opportunities (GSOO) were formally established to improve the transparency of
information, gas security and facilitate competition in the Western Australian Gas
Market.
24
gasTrading Australia Pty Ltd website. See; http://www.gastrading.com.au/about-us.html.
25
IMO (2014) SWIS Electricity Demand Outlook, June 2014, p. 42.
26
Ibid, p. 41.
27
Ibid, p. 41.
28
IMO (2014) SWIS Electricity Demand Outlook, June 2014, pp. 41-44.
Page 22 of 60
The purpose of the GBB and the GSOO, as set out in the Gas Services Information Act
2012, are:29
•
to improve the security, reliability and availability of natural gas supplies in
Western Australia;
•
promote the efficient operation and use of natural gas services;
•
provide information to allow efficient investment in natural gas services; and
•
encourage competition in the natural gas services supply chain.
The Independent Market Operator is responsible for maintaining Gas Services
Information. The first GSOO was published in July 2013 and the GBB became
operational on 1 August 2013.
The Emergency Management Facility (EMF) was also established in 2013 as part of the
recommendations from GSEMC. This is a dormant information collection platform that
sits within the Gas Bulletin Board. The role of the EMF is to assist in the management
of major gas supply incident by the provision of near real-time market information.
Hence, the EMF is only activated when the severity of the supply disruption requires
limited demand curtailment.30 The IMO activates the EMF on direction by the
Coordinator of Energy. Only users authorised by the Coordinator of Energy can view
information on the EMF, as some of the data is commercially sensitive.31
When the EMF is activated, the IMO informs all authorised participants to submit
requested data that is relevant to manage the supply disruption.32 Data supplied to the
EMF falls under three levels:33
•
data supplied to the GBB;
•
EMF standing information; and
29
WA
Department
of
Finance
website.
Gas
Services
Information
Project.
See;
https://www.finance.wa.gov.au/cms/Public_Utilities_Office/Energy_Initiatives/Gas_Services_Information_Proje
ct.aspx
30
WA Department of Finance website. Gas Services Information Project – Emergency Management Facility FAQ. See;
https://www.finance.wa.gov.au/cms/uploadedFiles/Public_Utilities_Office/Energy_Initiatives/EmergencyManagement-Facility-FAQ-(Approved)-21-January-2013.pdf.
31
Ibid.
32
The Coordinator of Energy can change data requested and user access to EMF.
33
WA Department of Finance website. Gas Services Information Project – Emergency Management Facility FAQ. See;
https://www.finance.wa.gov.au/cms/uploadedFiles/Public_Utilities_Office/Energy_Initiatives/EmergencyManagement-Facility-FAQ-(Approved)-21-January-2013.pdf.
Page 23 of 60
•
EMF requested data (from gas market participants registered and not registered
for the GBB).
In addition to the establishment of the GBB, GSOO and the EMF post the Varanus
Island incident, a statewide Emergency Management Plan for Gas Supply Disruption
(commonly known as the Westplan – Gas Supply Disruption) was formalised in 2013.
The Westplan – Gas Supply Disruption sets out the detailed arrangements of the actions
that would be undertaken to manage gas supply disruption incidents. Specifically; a
gas supply disruption would be managed in the following order of response:34
•
use of market mechanisms by market participants to manage their supply-side
and demand-side exposure, based on information available and provided to the
EMF;
•
curtailment plan – if market mechanisms are unable to balance supply and
demand, a curtailment plan should be enforced by market participants based on
that stipulated in contractual terms; and
•
energy rationing – gas would be rationed based on a pre-agreed Priority
Allocation Schedule.
In summary
Collectively, the above reforms to market arrangements and developments in supply
capacity have improved the resilience of the domestic gas market to supply disruption
shocks.
Compared to 2008, there is now a greater diversity of supply sources and more gas
available to be dispatched should the need arise; gas users have begun to take
advantage of the better terms being offered on supply contracts, which gives them
greater flexibility in balancing supply and demand; and, the DBNGP pipeline is less
vulnerable to failure due to extensive looping. In addition, market arrangements have
been reformed with the aim of establishing a better means of forward warning about
disruption incidents, better forward planning and coordination strategies for possible
disruptions and improved market efficiency through public disclosure of information
about short term and long term gas supply.
Stakeholder views and perspectives about the combined effect of these reforms and
developments are summarised in section 3.4 and in Appendix B.
34
WA Public Utilities Office (2013) State emergency management plan for gas supply disruption (Westplan – Gas supply
disruption), June 2013.
Page 24 of 60
3.3
Potential options available to retailers to manage
supply risk
Gas retailers can mitigate their supply risk with respect to major gas supply
disruptions through employing either ex-ante contingency measures or ex-post
reactive measures.
Contingency measures are arrangements made by gas retailers, in advance of a
potential supply disruption, to provide them with the ability to access additional
volumes of gas in the event that a disruption occurs. These measures can be
categorised as:
•
storage-based measures, including the storage of contingency gas supplies in
facilities such as the Mondarra storage facility or within the DBNGP; and
•
contract-based measures, including entering into flexible contracts including
options contracts, with gas producers (or other large gas users) for the purpose of
obtaining additional volumes of gas in the event of a supply shortfall.
Alternatively, gas retailers may choose to avoid the up-front and ongoing costs
associated with the above contingency measures by responding to gas supply
disruptions as they occur (i.e. on an ex-post basis). The response measures available to
gas retailers to meet the supply shortfall to small-use customers resulting from a gas
supply disruption include:
•
curtailment of supply to larger customers (declaration of force majeure), with gas
supplies diverted to small-use customers;
•
purchase of additional volumes of gas on a short-term basis through short-term
agreements with established gas suppliers or via spot trading platforms; and
•
reallocation of gas by retailers within their own portfolios, such as fuel switching
within dual-fuel electricity generators to make additional gas volumes available
for supply to small-use customers.
It is important to note that the measures available to gas retailers will vary based on the
nature of the gas supply disruption. Whilst a source of contingency supply may be
available to a gas retailer under one supply disruption scenario, a supply disruption of
a different nature could prevent the gas retailer from being able to access this
contingency supply. For example, an option-based contract with an alternative gas
producer (or another gas user) may be an effective hedge against the retailer’s primary
supplier being affected by a disruption, but it will not insure against the possibility of
the DBNGP being ruptured because no gas will able to be delivered to small use
Page 25 of 60
customers located south of the rupture point if the supplier is located north of the
rupture point.
3.4
Contingency
retailers
arrangements
currently
held
by
There are three retailers operating in the Western Australian gas market. While all
three service small use customers, Alinta has the largest market share (approximately
93% by volume), followed by Kleenheat (6%) and Synergy (less than 1%).35
In the course of this study, Synergies consulted with each retailer to understand the
type of contingencies held for managing major supply disruptions and how each
retailer would respond to a disruption event. The results of these discussions are
summarised in this section.
3.4.1 Retailers’ perspectives about disruption risk
Retailers were unanimous in their view that the potential adverse consequences of the
Karratha Gas Plant (KGP) plant failing are significantly lower than what they were in
2008. The main reason for this is the increased diversity of supply sources and volume
of supply. One retailer pointed out that at that time, the KGP supplied an estimated 70
per cent of the state’s natural gas requirements. But now the KGP now contributes just
38 per cent of Western Australia’s total natural gas processing capacity (based on the
December 2014 GSOO). And this is forecast to decline to 32 per cent by 2020 when the
Wheatstone and Gorgon projects become fully operational.
Another retailer noted the fact that their business now sources supply from a much
wider array of producers and is therefore much less exposed to the risk of obtaining all
gas from a single source, as was the case in 2008. The retailer noted that at present
about 60% of its supply comes from KGP and the remaining 40% is obtained from
multiple sources. Further, the retailer indicated that in the event of a disruption to KGP
it could obtain alternative supplies of gas from other producers at a price equal to or
less than what it is currently paying for gas ex KGP.
If KGP were to fail, the owner of the plant would bear the cost of revenue loss from the
production outage. This implies that to the extent gas was available from other
producers to make up the shortfall caused by the outage, retailers would only incur
costs equal to the net price of purchasing this gas (net of what they would have paid
for gas ex KGP). Based on information provided by the retailers, this net price is
35
Information collated in consultations with retailers between 26 March and 15 April 2015.
Page 26 of 60
expected to be low, zero or even negative (due to the highly competitive nature of the
market).
The perceived consequences of the DBNGP failing are potentially much more severe
than a disruption to KGP, depending on where the rupture occurs along the pipe.
Retailers noted that in the event of a pipeline rupture occuring along a looped section
of the pipe, the unaffected loop can continue to supply natural gas. Further, it was
noted that the pipeline owner, Dampier Bunbury Pipeline (DBP) maintains critical
spares of equipment and parts, enabling it to restore gas flows within an estimated five
days of a pipeline rupture. However if the disruption occurs in an unlooped section of
the pipe, as is the case described for scenarios 3 and 4, then there are no economically
feasible infrastructure options to mitigate against this. DBP estimates that, in a worse
case scenario, the pipeline may be shut down for up to 8 days if compressor station 9
failed. If such an event occurred, it would trigger an emergency situation under
Westplan – Gas Supply Disruption and all gas supplies to larger users (including those
served by retailers and those obtaining wholesale gas directly from producers) would
be curtailed in order to maintain supply to residential customers.
Less severe scenarios were considered to include the KGP failing for up to 180 days, or
pipeline failure for periods of less than five days. Retailers were unanimous in their
view that these scenarios could be adequately managed within their existing
contingency arrangements and/or responding to the event when it happens through
adjusting their gas portfolio (at relatively low cost) to ensure small use customers
remain unaffected.
Retailers reported that they have adopted a mix of strategies, which would be actioned
in various ways (and sequences) depending on the severity and length of the
disruption. The strategies referred to include the following:
•
utilisation of pipeline imbalances, including in-pipeline trading of gas where gas
surplus to needs at one location is reassigned to areas where there is a gas deficit;
•
sourcing of alternative gas supply from other suppliers or users, including
utilisation of flexibility in existing contracts, spot gas purchases and utilisation of
gas banking arrangements;
•
reallocation of gas from other parts of the retailer’s business – for example, in one
case this would involve reducing gas supply to electricity generation (and
replacing this with liquid fuels), and in another case would involve reducing gas
supply to the retailer’s LNG and/or LPG plants. These strategies would be used as
a means of redirecting the ‘saved gas’ into the retail natural gas market; and
•
curtailing large industrial and commercial customers; and
Page 27 of 60
•
utilising the Mondarra storage facility.
These arrangements are discussed further below.
3.4.2 Contract-based contingencies
One retailer noted that its contracts with its major supplier now contain a far greater
level of flexibility than has previously been the case. These contracts provide the
retailer with greater flexibility to source additional volumes of gas from alternative
suppliers, without penalty, in the event that there is a supply shortfall. The retailer also
has options clauses in some of its contracts with large industrial customers
(particularly in the mining sector), whereby the retailer is able to ‘buy back’ gas
volumes at a predetermined exercise price in order to meet supply shortfalls.
Similarly, it was said that there are numerous gas users in the market that are willing
to enter into options contracts to supply gas at a favourable price. These contracts have
become more common in recent years due to the strong supply-side competition and
diversity of gas supplies that now exist in the domestic gas market. We were advised
that both the cost of establishing these contracts, and the exercise price on the option,
have fallen in recent years, thus providing retailers with a relatively low-cost source of
contingency supply.
3.4.3 Fuel switching
Some retailers have the option of reallocating gas from the electricity-side of their
business to the gas retail side of their business. This affords the business increased
flexibility in managing supply disruptions and keeping supply in balance with
demand. We were advised that fuel switching has become more cost effective in recent
years due to technological improvements in cogeneration electricity turbines that can
operate efficiently on multiple fuel sources.
3.4.4 Storage-based contingencies
There are two types of storage-based contingency measures available to gas retailers to
improve their capacity to absorb a major gas supply disruption:
•
storage of gas in a facility, such as the Mondarra storage facility, with the gas
withdrawn from storage in response to a supply shortfall; or
•
storage of additional gas volumes in the DBNGP (referred to as ‘storage banking’).
Gas retailers have advised that storage banking is a significant part of their operations.
Storage banking is a provision in the contract that retailers have with their supplier.
Page 28 of 60
The provision comprises both a firm component and flexible component. Some of the
contracted gas must be taken, while the balance can be stored for later use.
With regard to Mondarra, Synergy has a contract with APA Group to inject, store and
withdraw gas in future periods. This gas storage and supply service is made available
to Synergy under contract, but other parties may be able to access this gas in the event
of a disruption if Synergy were to on-sell its rights.
Another retailer has a contract to store gas in Mondarra for short periods, mostly as a
means of managing short term imbalances between supply and demand and for
hedging against short term changes in price. The contract held by this retailer with
APA Group does not constitute a ‘firm service’ for injecting and withdrawing volumes
of gas. This means that these services are paid for when used, and can only be accessed
if available. Only the storage service is firm and fixed in price. Therefore in a gas
supply emergency the retailer holding this contract will not have access to gas
withdrawal services as these services will be sold to other users, thus making this
contract unsuitable for managing a major disruption.
Page 29 of 60
4
Modelling method and assumptions
This section presents an overview of the CEA model framework, including the
scenarios and options for which cost estimates have been estimated. Key model
assumptions and values for inputs are documented.
4.1
Overview of modelling steps
The economic modelling comprises five main steps, which are summarised in Figure 2
and described below.
Figure 2 Modelling steps
Step!1!
Step!2!
Step!3!
Step!4!
Step!5!
• Four!disrup/on!scenarios!modelled!by!Advisian!
• Two!/mings!–!peak!and!off!peak!demand!periods!
• Calculate!volume!shorBall!in!retail!supply!for!each!scenario!
• Express!shorBalls!rela/ve!to!‘business!as!usual’!demand!in!the!specified!period!
• Pro!rata!the!shorBall!to!each!customer!type!in!propor/on!to!current!consump/on!
• Calculate!the!volume!of!gas!(Y!TJ)!that!would!need!to!be!sourced!by!retailers!to!
maintain!full!supply!to!small!use!customers!
• Es/mate!the!costs!of!sourcing!Y!TJ!of!gas!using!each!of!5!op/ons!
• Express!costs!as!NPVs!over!a!30!year!/meframe!
• Compare!the!cost!of!each!op/on!rela/ve!to!Mondarra!
• Perform!sensi/vity!analysis!
!
Source: Synergies
4.1.1 Determ ining the supply shortfall caused by a disruption
The starting point (steps 1 and 2) is to establish the volume shortfall of gas (also
referred to as “unserved demand”) that is expected to arise under each disruption
scenario.
This estimate is obtained from Advisian’s risk modelling. We determine two different
measures of shortfall, depending on whether the shortfall is calculated before or after
Page 30 of 60
accessing gas from spare capacity. Advisian’s model is a physical ‘stocks and flow’
model, which means shortfall is calculated as the amount of demand unserved after
using all available gas in the system, including any spare production capacity that
could be utilised (only relevant for scenarios 1 and 2). However, in an economic
assessment of meeting supply disruption it is necessary to consider the cost of
accessing this spare capacity gas, so it is important to evaluate supply shortfalls caused
by a disruption before utilising any spare capacity. If it is assumed that spare capacity
gas could be accessed by retailers at no additional cost (relative to the price of gas
currently being paid ex KGP), then the analysis is reduced to examining the cost of just
servicing residual shortfalls (unserved demand after exhausting any available spare
capacity). But if retailers must pay a net increase in price for spare capacity gas, then
this additional cost must be incorporated into the analysis. We make provision in the
modelling for both possibilities and report the results of each in Chapter 5.
4.1.2 Assigning a proportion of the shortfall to sm all use custom ers
In step 3 the shortfall is assigned to each type of retail customer in proportion to their
current consumption (in a given period – peak or off peak). Therefore, small use
customers are assigned a notional volume of the gas shortfall, equivalent to the volume
that would otherwise be curtailed to this customer group if they were not given
priority through the Westplan – Gas Supply Disruption. It is assumed that this is the
volume of gas that would need to be acquired by retailers in order to maintain
continuous supply to small use customers.
In the instance that the KGP fails (scenarios 1 and 2), the shortfall is expressed in terms
of the percentage of total system demand (all gas users throughout the state) that is
unable to be served. For situations in which the DBNGP ruptures (scenarios 3 and 4) it
is assumed that only those users on the DBNGP south of the rupture will be affected.
Therefore, shortfalls are expressed in terms of the percentage of demand south of the
rupture that is unable to be served.
The shortfall of gas assigned to small use customers is subsequently calculated by
multiplying small use customer demand (under business as usual conditions) by the
percentage shortfall in demand experienced in aggregate by all affected users in each
of the above scenarios. A worked example of the calculation is provided in section
4.2.6.
4.1.3 Assessing the cost of each contingency option
In step 4 the cost to retailers of sourcing this gas through each of the five alternative
options is calculated.
Page 31 of 60
The five contingency options modelled are as follows:
•
purchasing the required volumes of gas under short-term contracts (either
bilateral contracts or via the spot market);
•
curtailing gas supply to large commercial and industrial gas customers (i.e.
declaration of force majeure and reallocation of gas volumes to small-use
customers);
•
reallocating gas within a gas retailers’ portfolio through the use of fuel switching
at electricity generators (i.e. substitution of gas for alternative fuels for electricity
generation and reallocation of gas volumes to supplying small-use customers);
•
entering into ex-ante options contracts with gas suppliers (or other large users) for
the volumes of gas required to meet supply shortfall for small-use customers
under the disruption scenarios; and
•
purchasing gas ‘up front’ and storing gas at Mondarra for future use when, and if,
a disruption event occurs.
Technically feasible contingency options
Some of the contingency options examined are not technically feasible for addressing
all disruption scenarios. The matrix in Table 1 summarises those contingency options
that are technically feasible (marked with a tick) and those that are not (marked with a
cross).
Gas can technically be obtained through any of the five contingency options under the
KGP failure scenarios (that is, scenarios 1 and 2). Responding to potential failures in
the unlooped sections of the DBNGP (scenarios 3 and 4) is more problematic. There are
fewer options available. For customers located downstream of the pipeline break it
would be impossible to service their needs by purchasing gas from alternative
producers located upstream of the break. Therefore, short term trading and the use of
options contracts are assumed to be technically infeasible.
Mondarra storage provides a potential contingency option for a pipeline rupture north
of the storage facility (scenario 3), but it would not be a feasible option if the pipeline
ruptured south of Mondarra (scenario 4) because all gas coming out of storage would
then need to be transported via the Parmelia Pipeline, which currently has a capacity
limit of 65 TJ per day. Whilst this technically constrains Mondarra from being a viable
option for managing scenario 4, we have nevertheless modelled the cost of this option
for comparative purposes, should the Parmelia Pipeline capacity constraint be
overcome at some future date.
Page 32 of 60
Table 1 Technical feasibility of options for each supply disruption scenario
Measure !
Scenario #1 !
Scenario #2 !
KGP fails with loss of KGP fails with loss
600TJ/d over 90 days! of 350 TJ/d over
180 days!
Scenario #3 !
Scenario#4 !
DBNGP fails north
of Mondarra for 7
days!
DBNGP fails south of
Mondarra for 7 days!
Short-term trading!
!
!
!
!
Curtailment of large customers!
!
!
!
!
Fuel switching at generators!
!
!
!
!
Options contracts!
!
!
!
!
Mondarra storage!
!
!
!
!
Source: Synergies assessment based on consultation with Advisian and industry stakeholders.
The costs are calculated over a 30 year timeframe and converted to NPVs. 36 This
enables the different timing of costs for different options to be validly compared
through discounting. Contingency options involving pre-emptive actions, which
include Mondarra and establishment of options contracts, involve a combination of upfront costs and annual costs – which are incurred irrespective of whether a disruption
event occurs (analogous to an insurance premium). The other options are reactive, and
therefore costs to respond to the disruption are only incurred in the year an event
happens. However, the timing and incidence of events are uncertain, we assume a
probability for each disruption scenario and weighting the cost of a particular incident
occurring by the annual probability of the event occurring. In this way, an annual
probability-weighted cost is calculated.
4.1.4 Com parison of cost effectiveness of each contingency option
The final step of the analysis (step 5) is to compare the costs of each contingency
option. This is done in both absolute terms and relative terms (relative to the cost of
Mondarra, which is used as a cost benchmark). The cost estimates are subjected to
sensitivity analysis wherein a number of input assumptions are varied to examine how
sensitive the results are to different input values.
4.2
Input assumptions
Details of the inputs and parameter values used for the economic modelling are set out
below.
36
See section Error! Reference source not found. for explanation of 30 year study period.
Page 33 of 60
4.2.1 Tim efram e for analysis
The CEA has been conducted over a 30-year period. As discussed in section 2.1, this is
based on standard methodology for evaluating the potential risks and returns to the
holders of an insurance policy.
4.2.2 Inflation rate
An inflation rate of 2.5% per annum has been applied in the analysis. This represents
the mid-point of the Reserve Bank of Australia’s target range for inflation.
4.2.3 Discount rate
As the CEA assesses costs that are incurred at different points in time, it is necessary to
discount values that occur in the future. As the analysis estimates the societal cost
impact of different responses to gas supply shortfalls as a result of supply disruptions,
it is appropriate to apply a social discount rate. In 2010, the Productivity Commission
published a research paper examining evidence of possible market benchmarks for the
social discount rate used in cost-benefit analysis. The review found that a range of 3%
to 10% (real) was appropriate.37 On this basis, a nominal discount rate of 9% (real
discount rate of 6.5% plus 2.5% to account for the impact of inflation) has been applied
in the analysis.38
4.2.4 Probability of scenarios
The annualised cost impact of the various responses by gas retailers to a shortfall in gas
supply are dependent on the incidence rate of the supply disruption scenarios that
have been assessed in this analysis. Table 2 summarises the annual incidence rate for
the disruption scenarios.
37
Harrison, M. (2010). Valuing the Future: the Social Discount Rate in Cost-benefit Analysis, Visiting Researcher
Paper, Productivity Commission, Canberra.
38
It is noted that Synergies typically applies a lower discount rate in conducting social cost-benefit studies (typically
the 10 year Australian Government bond yield is used as the social discount rate, representing the risk-free rate of
return. For this analysis, this would have resulted in a nominal discount rate of 4.84% (10-year bond rate of 2.34%
plus the inflation rate of 2.5%).
Page 34 of 60
Table 2 Likelihood of supply disruption scenarios
Disruption scenario !
Likelihood !
Annual probability of
disruption !
Loss of KGP (600TJ/d) for 3 months!
Once every 50-100 yrs!
1.33%!
Loss of KGP (350TJ/d) for 6 months!
Once every 50-100 yrs!
1.33%!
DBNGP failure downstream of CS7!
Once every 300-600 yrs!
0.22%!
DBNGP failure downstream of CS9!
Once every 300-600 yrs!
0.22%!
Source: Advisian (2015). Security of supply to small-use gas customers.
4.2.5 Gas dem and forecasts
The shortage of gas supply to small-use customers under the disruption scenarios has
been estimated on a pro-rata basis (i.e. the proportion of total gas supply lost has been
applied to small-use customer demand). Gas demand by small-use customers over the
study period will therefore inform the magnitude of the supply shortfall for small-use
customers under each disruption scenario. The following parameters were applied to
estimate forecast demand by small-use gas customers over the study period:
•
peak period (winter) gas demand by small-use customers of 70 TJ/day in 2015/16
•
off-peak period (summer) gas demand by small-use customers of 30 TJ/day in
2015/16.
The 2015/16 demand estimates are consistent with the parameter estimates that have
been applied by Advisian. No growth rate has been applied to small-use customer
demand over the study period, based on the observation that total gas consumption by
residential gas users in WA decreased at a rate of 1.1% from 2009 to 2014.39
4.2.6 Loss of supply under disruption scenarios
Noting that cost considerations and the application of the Westplan – Gas Supply
Disruption principles will prevent any actual loss of supply to small-use customers
under the disruption scenarios, the cost incurred in maintaining supply to small-use
customers under these scenarios has been estimated by pro-rating the total loss of gas
supply under each scenario across all customer segments. For example, if a disruption
caused gas users to experience a 30% aggregate loss in supply, the assigned loss of
supply to small-use customers is estimated to be equivalent to a 30% reduction in the
amount of gas currently supplied to small use customers.
Supply shortfalls are calculated in two ways – either before any spare capacity is
accessed, or the residual shortfall after any spare production capacity is utilised.
39
Independent Market Operator (2014) Gas Statement of Opportunities – December 2014.
Page 35 of 60
Residual supply shortfalls after utilising spare capacity
Table 3 sets out the estimated total supply shortfall under each supply disruption
scenario, based on modelling conducted by Advisian. The shortfalls are expressed as
total volume shortfalls for all users, relative to demand, and the proportion assigned to
small-use customers.
To demonstrate how the shortfall estimates for small use customers have been
calculated, consider the following worked example for disruption scenario 1 winter:
This scenario is estimated to cause a 7% shortfall in supply, relative to the ‘business as
usual’, total demand for gas by all users in the system. To calculate the volume of
shortfall assigned to small use customers, we multiply small use customer demand
during the winter peak (70 TJ/day) by 7% to get 4.92 TJ/day shortfall.
Note that Advisian’s modelling finds that there will be no shortfall under scenario 2.
This is because there is sufficient spare capacity in the system to offset the loss of 350
TJ/day.
Table 3 Residual supply shortfalls under each disruption scenario
Disruption scenario !
1. Loss of KGP (600TJ/d)
for 3 months!
2. Loss of KGP (350TJ/d)
for 6 months !
Period !
Total supply
shortfall
(TJ/day) !
Percentage of
demand
unserved !
Small-use
supply shortfall
(TJ/day) !
Winter (peak)!
65!
7%!
4.92!
Summer (off-peak)!
154!
15%!
4.55!
Winter (peak)!
0!
0%!
0!
Summer (off-peak)!
0!
0%!
0!
3. DBNGP failure
downstream of CS7 for 7
days!
Winter (peak)!
407!
79%!
55.11!
Summer (off-peak)!
493!
81%!
24.40!
4. DBNGP failure
downstream of CS9 for 7
days!
Winter (peak)!
399!
77%!
54.02!
Summer (off-peak)!
395!
65%!
19.56!
Note: (1) The shortfall estimates are calculated on the basis that the volume of gas stored in Mondarra under contract to Synergy would
be available in the event of a disruption (90 TJ/d for 30 days). The remaining 60 TJ/d of Mondarra capacity that has not been contracted
is modelled as one of the contingency options for potential uptake and thus has not been used to offset the supply shortfalls in this table.
(2) Winter is the peak period for direct consumption of gas by small-use customers. However, total consumption of gas in the domestic
market is highest in summer due to this being the time of peak demand for electricity by small use customers.
Source: Based on data provided by Advisian. See: Advisian (2015) Security of supply to small-use gas customers.
Figure 3 summarises the total shortfall to small-use customers over the entire duration
of each disruption scenario. Costs are calculated on the basis of mitigating these
volumes of supply shortfall.
Page 36 of 60
Figure 3 Total shortfall to small-use customer supply by disruption scenario (TJ)
!
Data source: Synergies modelling based on Advisian estimates. See: Advisian (2015). Security of supply to small-use gas customers.
Supply shortfalls before utilising spare capacity
Provision is made in the economic model for calculating the cost of accessing spare
capacity as a means of mitigating shortfalls. To facilitate this calculation, we use
estimates of total shortfall caused by a disruption, before netting off utilisation of spare
production capacity. The assumed volumes are summarised in Table 4.
This modelling demonstrates that, at worst, small use customers would incur a
notional loss of 43 TJ per day shortfall in gas supply, most of which would be able to be
sourced from other producers. Based on Advisian modelling only 5 TJ of this shortfall
would need to be mitigated through a contingency option (see Table 3).
Table 4 Total supply shortfalls under supply disruption scenarios
Disruption scenario !
1. Loss of KGP (600TJ/d)
for 3 months!
2. Loss of KGP (350TJ/d)
for 6 months !
Period !
Percentage of
demand
unserved !
Small-user
Total small-user
supply shortfall
shortfall over
(TJ/day) !
period (TJ) !
Winter (peak)!
62%!
43.13!
3439!
Summer (off-peak)!
56%!
16.87!
1108!
Winter (peak)!
36%!
25.35!
6879!
Summer (off-peak)!
33%!
9.91!
2217!
Source: Based on data provided by Advisian. See: Advisian (2015) Security of supply to small-use gas customers.
Page 37 of 60
4.2.7 Price of spare capacity gas
The analysis assumes that under scenarios 1 and 2 retailers will be able to access spare
gas at an equivalent (or lower) price to what they are currently paying for gas, ex KGP.
This is considered reasonable, given the strong supply-side competition in the current
market. Prices are only expected to increase once available spare capacity is exhausted,
leaving retailers with the option of purchasing gas from other users that are willing to
sell on the short term market (see section 4.2.8).
In order to assess the sensitivity of results to the net price of spare capacity gas, the
model is run using a net price of $3.00 per GJ (or $3000 per TJ).
4.2.8 Price of gas on the short-term m arket
Table 5 below summarises the estimated cost that would be incurred by gas retailers if
the supply shortfall for small-use customers were to be addressed through short-term
trading (either through spot market platforms or short-term agreements with willing
sellers of gas – i.e. users that were willing to sell). The cost estimates under each supply
disruption scenario are based on assumptions regarding the likely price of gas on the
short term market, taking into consideration current and historical spot market prices
and the total supply shortfall under each disruption scenario.
The variation in the prices across the four scenarios are based on historical short-term
gas prices observed through the GasTrading platform and the views of industry
stakeholders regarding the likely impact of the supply disruption scenarios on the
price of gas in the short term.
Table 5 Incremental cost of sourcing lost gas volumes through short-term trading
Disruption scenario !
Cost of securing gas through short-term
trading !
Loss of KGP (600TJ/d) for 3 months!
$6,000 per TJ
Loss of KGP (350TJ/d) for 6 months!
!
$6,000 per TJ !
DBNGP failure downstream of CS7!
$10,000 per TJ
DBNGP failure downstream of CS9!
a
a
!
$10,000 per TJ !
b
b
a These estimates are based on industry stakeholder views that the level of supply disruptions under these scenarios would not be
sufficient to cause a material disruption to the cost of gas on either the spot market or through short-term contracts.
b These estimates are commensurate with the highest price that has been observed on the spot market operated by GasTrading since
July 2009 and are also consistent with industry stakeholder reviews regarding the likely impact of a significant disruption to gas supply on
the price of gas on the spot market and through short-term contracts.
Source: Estimates based on pricing data obtained from GasTrading – See: www.gastrading.com.au/spot-market/historical-prices-andvolume.html and through discussion with industry stakeholders.
Page 38 of 60
4.2.9 Cost of fuel switching contingency option
The cost incurred by gas retailers in maintaining supply to small-use customers during
a supply disruption by switching its fuel use in its dual-fuel electricity generation
facilities is determined by:
•
the type of alternative fuel that is used for power generation;
•
the quantity of the alternative fuel required to replace the foregone gas volumes;
and
•
the cost of the alternative fuel.
• For this analysis, it has been assumed that gas retailers would switch from gas to
diesel at their dual-fuel generators. It is estimated that 27.7 litres of diesel is required to
replace the energy that is generated by 1 GJ of gas.40 The cost of diesel has been
estimated at $1.39 per litre, based on the average diesel wholesale Terminal Gate Price
for Perth over the past four calendar years.41 Based on these estimates, gas retailers
would incur a cost of approximately $38,500 for every TJ of gas that would be
reallocated from electricity generation to small-use gas customers.42
4.2.10 Cost of curtailm ent option
In the event that gas retailers meet a shortfall in supply to small-use customers by
curtailing supply to larger customers, these larger customers will incur a welfare loss.
Attachment B sets out the approach that has been applied to estimate this welfare loss
under each of the supply disruption scenarios. An alternative approach to estimating
this cost would be to estimate the compensation costs that would be incurred by gas
retailers as a result of curtailing supply to customers. However, the welfare loss
approach that has been applied is considered a more accurate representation of the
economic cost of the curtailment of gas supply.
In order to estimate the cost of responding to a supply shortfall for small-use
customers by curtailing supply to larger customers, it is necessary to apply estimates
for:
•
the average price paid for gas by customers;
40
‘Understanding Energy Equivalency’ – Go With Natural Gas. DOA:
http://www.gowithnaturalgas.ca/getting-started/understanding-energy-equivalency/
16
April
2015.
See:
41
Australian Institute of Petroleum – Calendar Year and Financial Year Averages for Petrol and Diesel.
42
Based on consultation with Alinta, it is not anticipated that a material switching cost would be incurred in
substituting gas for diesel at dual-fuel generators in the event of a gas supply disruption.
Page 39 of 60
•
the volume of gas currently consumed by large customers that could be subject to
curtailment; and
•
the price elasticity of demand for gas.
•
The assumed values for each of these parameters are as follows.
Gas price
An estimate of $6/GJ (or $6,000/TJ) has been applied for the average price paid by
curtailed customers based on the forecasts developed by the National Institute of
Economic and Industry Research (NIEIR) for 2015 to 2024, and through consultation
with industry stakeholders.43
Gas consumption
An estimate of 55 TJ/day has been applied for the volume of gas that is supplied to
customers that could be subject to curtailment, based on consultation with industry
stakeholders.44
Price elasticity of demand
Given the lack of information available regarding the price elasticity of demand for
commercial and industrial gas users in Western Australia, elasticity estimates derived
from other studies were considered. According to a report prepared by Deloitte Access
Economics in October 2013, a review of literature on the demand for natural gas
demonstrated that the short and long-term price elasticity of demand were relatively
inelastic and ranged from -0.25 to -0.5.45 On this basis, an estimate for the price
elasticity of demand of -0.4 has been applied in this analysis. Given the importance of
this parameter, sensitivity analysis has been performed using alternative elasticity
estimates (see section 5.4).
Based on the above assumptions, the unit cost of curtailment ranges (for example) from
$13.36 per GJ (when 25 TJ per day is curtailed) to $33.83 per GJ (when 40 TJ per day is
curtailed). The assumed welfare loss function produces non-linear estimates of cost
impact with progressively higher levels of curtailment. This means that the marginal
43
Independent Market Operator (2014). Gas Statement of Opportunities December 2014, p 66.
44
It is important to note that this estimate applies to the volume of gas that is supplied to larger customers that could
be curtailed in order to meet a supply shortfall for small-use customers.
45
Deloitte Access Economics (2013). The economic impacts of a domestic gas reservation.
Page 40 of 60
value of gas to users is assumed to increase as progressively more gas is curtailed. For
this analysis we have capped the unit cost of curtailment to $33.83 per GJ.46
4.2.11 Cost of purchasing gas through options contracts
In the event of a supply shortfall due to a disruption, gas retailers have the ability to
source additional volumes of gas through options contracts agreed upon with gas
producers or users on an ex-ante basis. This is effectively a pre-emptive contingency
measure that could be adopted to mitigate against the risk of meeting shortfalls that
could not be covered through purchases of spare capacity gas at the time of the
disruption. The cost associated with this measure includes two components:
•
a fixed annual component that is incurred regardless of whether the contingency
supply is required; and
•
a variable component that is only incurred where gas volumes are actually
supplied.
Estimates of $0.50/GJ ($500/TJ) and $6/GJ ($6,000/TJ) respectively have been applied
for these costs (across all supply disruption scenarios), based on consultation with
industry stakeholders. The estimate for the cost of the fixed annual component is
relatively low due to the significant supply-side competition and surplus gas supply in
the market resulting in gas producers being willing to provide flexibility in contractual
agreements with gas retailers and other customers at relatively low cost.
4.2.12 Cost of storing gas supply in the M ondarra storage facility
Gas retailers have the option of taking the pre-emptive measure of securing
contingency supplies for small-use customers by contracting for the storage of
contingency gas supply in Mondarra. This has been assessed as the measure that
would be implemented in the event that gas retailers were required to physically store
gas to comply with a GCSO for small-use customers. Mondarra has the capability of
injecting up to 50 TJ/day into the Parmelia Pipeline.
However, it is noted that the extent to which Mondarra constitutes a reliable
contingency supply option is subject to the nature of the disruption. This is due to the
limited capacity of the Parmelia Pipeline to supply gas to small-use customers in the
event that a supply disruption occurs due to the incapacitation of the DBNGP south of
46
See Appendix B for an explanation for why unit costs were capped at this level.
Page 41 of 60
Mondarra.47 Despite this, the cost of this measure has been assessed under this
disruption scenario to provide an indication of the cost that would be incurred if these
infrastructure constraints were to be overcome.
There are three components to the cost of this option:
•
the cost associated with the storage of the gas at Mondarra;
•
the up-front cost of acquiring the contingency gas volumes, including the cost of
transporting the gas to Mondarra; and
•
the cost of transporting the gas from Mondarra to small-use customers (only
incurred in the event that the contingency supplies are required).
APA Group has informed Synergies that the cost of providing storage for contingency
gas supplies for small-use customers would be approximately $8 million per annum.
This is a fixed charge that covers injection, storage and withdrawal services for up to 50
TJ/d of gas for three months.
The cost of the gas itself and transmission of the gas down the DBNGP or Parmelia
Pipeline is additional to the fixed charge. The up-front cost of securing the contingency
gas volumes is assumed to be $5/GJ ($5,000/TJ), which includes:
•
$3,500/TJ for the purchase of the gas, based on the average spot market price on
the gasTrading platform over the past six months;48 and
•
$1,500/TJ for the transportation of the gas to Mondarra, based on consultation
with industry stakeholders.
The cost of transporting the contingency supplies from Mondarra to small-use
customers in the event of a supply disruption is assumed to be $1,500/TJ, based on
consultation with industry stakeholders.
47
According to industry stakeholders, under this scenario (disruption scenario 4), the Parmelia pipeline would only
be able to supply 15 TJ/day to small-use customers.
48
‘Historical Prices and Volume’. gasTrading Australia Pty Ltd. DOA:
http://www.gastrading.com.au/spot-market/historical-prices-and-volume.html
15
April
2015.
See:
Page 42 of 60
5
Model results
This section presents the results of the cost effectiveness analysis. The results are
summarised for each contingency option and disruption scenario. Only technically
feasible options for addressing supply shortfalls under each scenario are modelled
(infeasible options are shaded grey in the results tables). Further, no results are
presented for scenario 2 because no shortfall is estimated to arise under this scenario
(as explained in chapter 4).
5.1
Comparative analysis of contingency options
5.1.1 Cost of contingency options before weighting by incident
probability
Table 6 presents estimates of the cost of each contingency option if a supply disruption
was to occur in 2015/16. These costs are provided for reference purposes only. They
are insufficient for informing which option is most cost effective at responding to a
disruption at some future, unknown time because the analysis assumes that the next
disruption will occur, with certainty, in 2015-16. Of course this is unrealistic because
we do not know when the next disruption will happen.
Therefore the costs presented in Table 6 represent the costs of mitigating supply
shortfalls, using a range of options, before considering risk of disruption (probability of
occurrence) and timing differentials between the contingency options with respect to
when mitigation costs are incurred.
Table 6 Estimated cost of contingency options for mitigating supply disruptions to small use
customers (assuming the disruption occurs in 2015/16)
Contingency option !
Scenario #1 !
Scenario #3 !
Scenario #4 !
KGP fails with loss of
600TJ/d over 90 days !
DBNGP fails north of
Mondarra for 7 days !
DBNGP fails south of
Mondarra for 7 days !
Peak !
Off-peak !
Peak !
Off-peak !
Peak !
Off-peak !
Short-term trading!
$2.71m!
$2.52m!
!
!
!
!
Curtailment of large customers!
$3.05m!
$2.81m!
$13.37m!
$2.22m!
$13.12m!
$1.47m!
Fuel switching at generators!
$17.40m!
$16.20m!
$15.22m!
$6.74m!
$14.93m!
$5.40m!
Options contracts!
$2.94m!
$2.73m!
!
!
!
!
$10.47m!
$10.31m!
$10.85m!
$9.34m!
$10.82m!
$9.11m!
Mondarra storage
a
!
a Includes the cost of procuring gas for storage in the Mondarra reservoir (sufficient to supply 50 TJ/d for 30 days).
Note: Shaded cells indicate that the contingency option is technically infeasible to mitigate the shortfall under a particular disruption
scenario.
Source: Synergies modelling.
Page 43 of 60
The key findings are as follows:
•
For scenario 1, the most expensive contingency option is fuel switching. If the
disruption occurred in winter, at peak demand for gas, it would cost an estimated
$17.4 million to meet the supply shortfall to small use customers under scenario 1
if all the shortfall was covered through fuel switching.
•
Mondarra storage is the next most expensive option for scenario 1, estimated at a
cost of $10.47 million (for purchase, storage and withdrawal of gas). The other
three options are considerably cheaper, ranging from $2.71 million (for short-term
trading) to $3.05 million (for curtailment of large use customers).
•
There are fewer available contingency options under scenarios 3 and 4 as some are
not technically feasible. Of the three that are potentially feasible, fuel switching
remains a relatively more expensive option than the others in mitigating shortfalls
during periods of peak demand.
•
The results show that it would cost up to $15 million (through fuel switching) to
mitigate the supply shortfall to small used customers caused by a 7 day rupture of
the DBNGP. If additional gas was purchased and stored in Mondarra as a
contingency against supply disruption, the cost of meeting the shortfall to small
users would be up to $10.85 million.
•
However, these costs of contingency assume that the disruption occurs next year,
and the timing is known with certainty. The next section presents results that
demonstrate how the relative costs of contingency options change when costs are
weighted by the probability of a disruption occurring and timing effects are
incorporated into the analysis.
5.1.2 Probability-weighed cost of contingency options
Table 7 presents the cost estimates for each option. The costs are expressed as NPV
terms over 30 years (2015 dollars). Those costs that would only be incurred if an
incident occurred (for example, short term purchase of gas, curtailment and fuel
switching), are weighted by the probability of a disruption incident. The cost of options
involving annual or upfront costs, irrespective of whether an incident occurs, are not
weighted.
Page 44 of 60
Table 7 Summary of cost estimates by contingency option and scenario (NPVs)
Contingency option !
Scenario #1 !
Scenario #3 !
Scenario #4 !
KGP fails with loss of
600TJ/d over 90 days!
DBNGP fails north of
Mondarra for 7 days!
DBNGP fails south of
Mondarra for 7 days!
Peak !
Off-peak !
Peak !
Off-peak !
Peak !
Off-peak !
Short-term trading!
$0.47m!
$0.43m!
!
!
!
!
Curtailment of large customers!
$0.52m!
$0.48m!
$0.38m!
$0.06m!
$0.38m!
$0.04m!
Fuel switching at generators!
$3.00m!
$2.79m!
$0.44m!
$0.20m!
$0.43m!
$0.16m!
Options contracts!
$3.39m!
$3.16m!
!
!
!
!
Mondarra storage!
$108.40m!
$108.25m!
$108.04m!
$107.02m!
$108.01m!
$106.86m!
Notes: (1) Shaded cells indicate that the measure is considered to be technically infeasible; (2) The cost estimates for curtailment
represent the economic welfare loss incurred by curtailed gas users. Compensation costs are not included, because to do so would result
in double counting the cost.
Source: Synergies modelling.
The key findings of this analysis are:
•
Mondarra storage is a considerably more expensive option for maintaining gas
supply to small use customers than the other four options.
•
Short term trading and curtailment of gas to large customers are the cheapest
options for managing a disruption under scenario 1 (failure of the KGP).
•
Under scenarios 3 and 4 (the pipeline ruptures) the only options available are
curtailment of large users, fuel switching, and Mondarra storage.49 The results
demonstrate that curtailment and fuel switching are the cheapest options by a
very large margin. This is attributable to:
49
−
the relatively low cost of obtaining sufficient volumes of gas through these
measures at the time of an incident to meet small use demand ($13 million for
curtailment or $15 million for fuel switching under a scenario 3 disruption in
a period of peak demand);
−
the very low assumed probability of a rupture to the DBNGP (once in every
300 to 600 years); and
−
the fact that the Mondarra option involves payment of a fixed storage fee of
$8 million each year to insure against a potential (low probability) loss of
supply to small use customers that would cost, at most, $15 million (see Table
5) to mitigate through fuel switching or curtailment in the year that it
occurred.
Mondarra is unlikely to be a viable option under scenario 4 due to pipeline capacity constraints in accessing the gas,
however cost estimates are presented for comparative purposes.
Page 45 of 60
5.1.3 Im pact of including a cost of accessing spare capacity gas
The analysis used to generate the above results (those presented in Table 7) assumes
that under scenarios 1 and 2 retailers will be able to access spare gas at an equivalent
(or lower) price to what they are currently paying for gas, ex KGP. Thus the standard
set of results is based on a zero net price for accessing spare capacity gas. If the model
is re-run using a net price of $3 per GJ we find that this adds the following mitigation
costs to each scenario (expressed as probability-weighted NPVs over 30 years):
•
Scenario 1, peak demand: $1.82 million
•
Scenario 1, off-peak demand: $0.59 million
•
Scenario 2, peak demand: $2.3 million
•
Scenario 2, off-peak demand: $0.9 million
•
This sensitivity analysis demonstrates that even if retailers must pay $3.00 per GJ
more for gas purchased through another supplier, the additional cost of this in
probability-weighted terms over 30 years is relatively minor, and is not sufficient
to make Mondarra a cost-competitive contingency option relative to the other
options.
5.2
Cost breakdown for the Mondarra storage option
Table 8 summarises the breakdown of costs for the Mondarra storage and how each
cost item varies under each scenario. As before, the costs are expressed in NPV terms
over 30 years. With the exception of transportation costs associated with the
withdrawal of gas in response to a supply disruption, all other costs (gas procurement
and the annual storage service fee) are incurred irrespective of whether a disruption
occurs. Therefore, only transportation costs are weighted by the probability of a
disruption.
The results in Table 8 show that there is very little variation in the estimated cost of
storing contingency gas in Mondarra across the supply disruption scenarios. This is
because the cost of this measure mostly comprises the annual fixed cost of storing gas,
which is the same for all scenarios ($8 million per year, or $106 million NPV over 30
years). The minor cost differential across the scenarios is therefore caused primarily by
the different volumes of gas withdrawn from Mondarra to meet the shortfalls arising
under a particular scenario.
Page 46 of 60
Table 8 Cost of storing contingency supply in the Mondarra storage facility (NPV terms)
Cost item !
Scenario #1 !
Scenario #3 !
Scenario #4 !
KGP fails with loss of
600TJ/d over 90 days!
DBNGP fails north of
Mondarra for 7 days!
DBNGP fails south of
Mondarra for 7 days!
Peak !
Off-peak !
Peak !
Off-peak !
Peak !
Off-peak !
Fixed annual storage cost!
$106.21m!
$106.21m!
$106.21m!
$106.21m!
$106.21m!
$106.21m!
Up-front cost of procuring
gas!
$2.07m!
$1.93m!
$1.81m!
$0.80m!
$1.78m!
$0.64m!
Cost of transporting gas!
$0.12m!
$0.11m!
$0.02m!
$0.01m!
$0.02m!
$0.01m!
$108.40m!
$108.25m!
$108.04m!
$107.02m!
$108.01m!
$106.86m!
Total cost !
Notes: Although a cost estimate has been derived for scenario #4, it is considered that the storage of contingency supplies in Mondarra
will not represent a viable option under this scenario due to pipeline capacity constraints in accessing the gas.
Numbers may not add due to rounding.
Source: Synergies modelling.
5.3
Cost of contingency options relative to Mondarra
storage
Table 9 presents cost estimates for each option relative to Mondarra storage. The cost
relativities are therefore presented as percentages of the Mondarra base case. The
purpose of this analysis is to demonstrate the cost of insuring against each supply
disruption using a particular option (other than storage), and how this cost compares
relative to storing gas in Mondarra.
The analysis is limited to situations in which supply disruptions occur during the peak
period of gas demand (i.e. winter), as this is when the supply shortfall for small-use
customers is the greatest. Further, it is assumed that spare capacity gas must be
purchased for a net price of $3.00 per GJ (that is, $3.00 more than what retailers are
currently paying for gas ex KGP).
The results in Table 9 demonstrate that the cost of non-storage options, for the purpose
of maintaining supply to small use customers, is a fraction of the cost of Mondarra. For
example, the expected shortfall in gas caused by failure of the KGP could be met
through short term trading at a cost that is just 2.1% of that of Mondarra.
It should also be noted that due to current infrastructure constraints, in particular the
capacity of the Parmelia Pipeline to supply gas to ATCO’s reticulated network,50 it is
highly uncertain as to whether the Mondarra storage option would provide a reliable
source of contingency supply under scenario 4.
50
Based on stakeholder consultation, it is understood that the Parmelia pipeline would only have the capacity to inject
15TJ/day of supply to small-use gas customers under disruption scenario 4.
Page 47 of 60
Table 9 Cost of options relative to Mondarra storage
Contingency/response option !
Scenario #1
Scenario #3
Scenario #4
(peak) !
(peak) !
(peak) !
KGP fails with loss of
600TJ/d over 90 days!
DBNGP fails north of
Mondarra for 7 days!
DBNGP fails south of
Mondarra for 7 days!
$108.40m!
$108.04m!
$108.01m!
Short-term trading!
2.1%!
!
!
Curtailment of larger customers!
2.2%!
0.4%!
0.3%!
Fuel switching at generators!
4.4%!
0.4%!
0.4%!
Options contracts!
4.8%!
!
!
!
Cost of Mondarra contingency supply!
Cost of other options relative to Mondarra !
Note: Shaded cells indicate that the measure is not technically feasible under the disruption scenario.
Source: Synergies modelling.
5.4
Sensitivity analysis
Sensitivity analysis was conducted on the following parameters:
•
the price of gas secured through short term market;
•
the annual cost of storing gas in the Mondarra storage facility;
•
the incidence rates (probability) of the supply disruption events; and
•
the price elasticity of demand for gas for customers subject to curtailment.
These parameters were selected having consideration for their effect on the results of
the analysis and the uncertainty of the parameter estimates adopted. The effect of
changes to these parameters was assessed for the results relevant to each individual
parameter. For example, the effect of applying a 50% increase to short-term gas prices
under the disruption scenarios has only been assessed for those scenarios in which
short-term trading is considered to be a feasible contingency option.
Table 10 summarises the sensitivity analysis results. The analysis has only been
undertaken for the peak period, as this is the period in which the supply shortfall for
small-use customers is greatest.
Page 48 of 60
Table 10
Sensitivity analysis results
Contingency/response option !
Scenario #1
Scenario #3
Scenario #4
(peak) !
(peak) !
(peak) !
KGP fails with loss
of 600TJ/d over 90
days!
DBNGP fails north
of Mondarra for 7
days!
DBNGP fails south
of Mondarra for 7
days!
!
!
!
$108.40m!
$108.04m!
$108.01m!
Short-term trading!
2.1%!
!
!
Curtailment of larger customers!
2.2%!
0.4%!
0.3%!
Fuel switching at generators!
4.4%!
0.4%!
0.4%!
Options contracts!
4.8%!
!
!
2.3%!
!
!
$55.30m!
$54.94m!
$54.90m!
Short-term trading!
4.2%!
!
!
Curtailment of larger customers!
4.2%!
0.7%!
0.7%!
Fuel switching at generators!
8.7%!
0.8%!
0.8%!
Options contracts!
9.4%!
!
!
$108.06m!
$108.03m!
!
Base case!
Cost of Mondarra contingency supply!
Cost of other options relative to Mondarra !
50% increase in the short term gas price !
Short-term trading (relative to Mondarra)!
50% reduction in the annual cost of storing gas in Mondarra !
Cost of Mondarra option!
Cost of other options relative to Mondarra!
100% increase in incidence rate of supply disruption events !
Cost of Mondarra option!
$108.52m!
Cost of other options relative to Mondarra!
Short-term trading!
4.2%!
!
!
Curtailment of larger customers!
4.3%!
0.7%!
0.7%!
Fuel switching at generators!
8.9%!
0.8%!
0.8%!
Options contracts!
6.9%!
!
!
50% reduction in price elasticity of demand for curtailed customers (from -0.4 to -0.2) !
Curtailment of large customers (relative to Mondarra)!
2.2%!
0.5%!
0.5%!
Note: Shaded cells indicate that the measure is not technically feasible under the disruption scenario.
Source: Synergies modelling.
Increase in short term gas price
Purchasing gas on the short term market becomes a relatively more expensive option
when the price of gas is increased by 50% from the base case assumption of $6/GJ to
$9/GJ. However, it is still a cheap option relative to Mondarra. The cost of managing
small customer shortfall through buying gas on the market increases from 2.1% to 2.3%
of Mondarra’s cost.
Page 49 of 60
Reducing the annual storage facility fee
A halving of the annual storage facility fee (from $8m to $4m) reduces the NPV cost of
the Mondarra storage option by just under half. However, even at this significantly
reduced cost the other options remain much more cost effective (for example, in the
case of scenario 1 the most expensive option after Mondarra are options contracts at
9.4% the cost of Mondarra).
Increasing the probability of incidents
A 100% increase in the probability of disruption events occurring increases the cost of
all options relative to Mondarra, but not by much. For example, the cost of fuel
switching under scenario 1 increases from 4.4% of the cost of Mondarra to 8.9%.
We also calculated what level of probability of a disruption incident would be required
to make a decision maker indifferent between selecting Mondarra or another option
based on cost-effectiveness. The results are summarised in Table 11. For example,
scenario 1 would need to occur once in every 3.3 years for Mondarra to match the cost
effectiveness of fuel switching as an option for securing sufficient quantities of gas to
meet small-use customer demand. This is an unrealistically high probability. Similarly
for the other options, high frequency rates would be required for the cost of Mondarra
to break even.
Table 11 Required frequency of disruption events to equalise the cost of Mondarra to other
contingency options
Alternative measure !
Short-term trading!
Curtailment of larger users!
Fuel switching!
Options contracts!
Annual incidence rates at which cost of Mondarra is equal to alternati ve
measures !
Scenario 1 !
Scenario 3 !
Scenario 4 !
0.6632
!
!
(Every 1.5 years)!
0.6459
0.6571
0.6703
(Every 1.6 years)!
(Every 1.5 years)!
(Every 1.5 years)!
0.3063
0.5735
0.5850
(Every 3.3 years)!
(Every 1.8 years)!
(Every 1.7 years)!
0.6453
!
!
(Every 1.6 years)!
Note: (1) The incidence rates have been calculated based on supply disruptions occurring in the peak period; (2) Analysis assumes that
retailers incur an additional cost of $3/GJ in accessing spare production capacity; (3) Shaded cells indicate that the measure is not
technically feasible under the disruption scenario.
Source: Synergies modelling.
More inelastic demand for gas by curtailed customers
The cost of curtailing gas supply to large customers is assumed in this analysis to be a
function of the customer’s demand elasticity for gas. The more inelastic, the greater the
Page 50 of 60
costs imposed due to the customer having fewer substitute sources of fuel or
alternatives to gas in production of output. The analysis shows that even at a lower
elasticity of -0.2, the cost of curtailment is still low relative to Mondarra under all
scenarios. For example, in the case of scenario 1, the cost of curtailment is estimated to
be just 2.23% of the cost of Mondarra, compared to 2.16% when an elasticity of -0.4 is
assumed. Therefore, while the cost of curtailment as an option increases in absolute
terms, it is a very small increase in relative terms.
Page 51 of 60
6
Conclusion
This report opened with a number of questions:
•
what is the nature of the supply disruption risk in terms of likely incidence and
economic cost of responding to a disruption caused by physical failure of the
pipeline or gas production facilities?
•
how have the gas supply chain and market arrangements changed since 2009, and
have these changes lessened the economic costs and risk of a disruption?
•
what strategies are retailers currently using to manage the risk of major
disruptions?
•
do these current strategies represent a cost effective and efficient means of
maintaining supply to small use customers or would there be a net economic
benefit from imposing a GCSO?
The findings of the report provide answers to each of these questions, which form the
basis of our conclusions. These are set out below.
The risk of a gas processing plant disruption is material but manageable
Disruption incidents to gas production plants can, and do, occur from time to time.
However this study finds that, compared to the situation in 2008, gas retailers now
have multiple options to manage this form of supply risk. There is now considerably
more diversity in supply sources and supply capacity has increased markedly. This has
enabled retailers to take forward positions in the market at relatively low cost as a
means of securing gas from a diversity of suppliers to meet supply shortfalls.
Furthermore, at worst, small use customers would incur a notional loss of 43 TJ per
day shortfall in gas supply, most of which would be able to be sourced from other
producers at minimal or no additional cost to what retailers are currently paying for
gas ex KGP. Based on Advisian modelling only 5 TJ of this shortfall would need to be
mitigated through a contingency option.
Whilst the volume of gas required to maintain the integrity of the articulated ATCO
network (i.e. prevent depressurisation of the network) may be materially greater than 5
TJ/day, the Terms of Reference for this analysis has been limited to assessing the
economic case for implementing a GCSO for small-use customer supply only.
Determining whether there is economic justification for a mandatory CGSO necessary
to maintain the integrity of the reticulated network in the event of a major gas supply
disruption would require further analysis.
Page 52 of 60
The economic consequences of the DBNGP failing are significant but the risk is very
low
If the DBNGP was to rupture in an unlooped section, this would represent a more
severe disruption because it would prevent the flow of gas from the major production
plants in the north to areas of demand in the south. Faced with this scenario, retailers
would have limited options available. Based on Advisian’s modelling, we estimate that
up to 55 TJ/d would need to be ‘found’ in the system to maintain gas supply to small
use customers. This amount of gas could be obtained through curtailing all large
customers and/or switching electricity generators to alternative fuel sources. This
would cost up to $15 million in the year of the incident. However, as the probability of
pipeline failure is estimated to be very low (just 1 in 300 to 600 years), this cost reduces
to just $0.44 million in probability-weighted NPV terms (over a 30 year timeframe).
Storage of gas in Mondarra is a possible alternative option (provided the rupture is
north of Mondarra), but significantly more expensive, given that the storage access fee
proposed by Mondara’s owner is $8 million per year (a cost that is incurred
irrespective of whether an incident occurs or not). When this cost is aggregated over a
30 year timeframe the cost becomes $107 million in NPV terms.
Are retailers using the least cost option (or options) to manage risk?
It is difficult to be definitive about whether retailers are currently using the least cost
(optimal) mix of options for managing disruption risk because retailers were unwilling
to disclose specific details about supply contracts and how they balanced customer
demand against available supply through fuel switching and the like. Nor could we
determine an estimate of the cost of contingency currently held by each retailer.
However, by modelling the costs of each option as a stand-alone measure it has been
possible to develop an understanding of the magnitude of cost involved in taking preemptive action through adoption of one or more mitigation measures, relative to the
cost of responding to disruption events when and if they occur.
As demonstrated above, the cost of storing gas in Mondarra as a contingency measure
is very expensive option for maintaining supply to small use customers relative to
other options that retailers have available. This finding holds true over a wide range of
model parameters.
There are significantly cheaper options available than Mondarra and it is observed that
these options are being utilised by retailers. While curtailment of gas to large users
remains an option for responding to a gas plant failure (as a means of maintaining
supply to small use customers), the majority of stakeholders consulted in the course of
this study indicated that retailers would action other options ahead of curtailment if
Page 53 of 60
possible. The availability of diverse sources of gas supply at relatively low prices
(compared to several years ago) would suggest that sourcing additional supply on the
market or through pre-existing options contracts would be utilised by retailers ahead
of curtailment.
There is no economic case for a CGSO
It is concluded that there is no economic case for a CGSO because the gas requirements
of small use customers can be maintained at relatively small cost by responding to an
event when, and if, it happens. Further, it is evident that retailers are hedging some of
their risk exposure through contractual means and, given the relatively small volumes
of gas that would need to be found to maintain small use customer demand, there
would be minimal, if any, economic benefit from requiring retailers to adhere to a
mandatory contingency service obligation.
Page 54 of 60
A
List of stakeholders consulted
The following industry stakeholders were consulted:
•
Alinta Energy
•
APA Group
•
ATCO Australia
•
Dampier Bunbury Pipeline
•
Independent Market Operator
•
Kleenheat Gas
•
North West Shelf Gas
•
Public Utilities Office
•
Public Utilities Office – Emergency Management
•
Retail Energy Market Company
•
Synergy (wholesale and retail divisions)
•
Western Power – System Management.
Page 55 of 60
B
Table B.1
Summary of consultation findings
Summary of key themes emerging from stakeholder consultations
Theme !
Retailers !
Pipeline and storage operators ! Gas producers !
Market regulators and
operators !
Key gas market developments since
2009 (including changes in the
supply chain)!
Noted developments were:
Much more stable environment now
compared to 2008. Surplus supply.
Majority of DBNGP has been looped
•
More suppliers and increase total
production capacity
•
Greater liquidity in various spot
markets
•
•
Mondarra storage facility
Lower wholesale gas prices and
more flexible terms for contracts,
driven by greater competition in
wholesale supply !
The market is now quite resilient to
disruptions.
NSWG now only supplies 40-50% of
domestic demand. This will decline
further to just 30-30% once Gorgon
and Wheatstone come online.!
DBP has a new storage facility (1PJ)
which it uses to manage line pack
Increased production capacity and
diversity of supply sources (currently a
large surplus above demand)
Through the EMF, the PUO now gets
very good disclosure from industry; “the
answers are always in the room”
One stakeholder noted that while new
production has come online, the major
gas retailer still gets 80-90% of its gas
from a single producer, so is still at risk
of a supply disruption.
!
!
Standard behaviours in the market!
One retailer observed that during the
2008 Varanus Island incident, another
competing supplier of wholesale gas at
the time curtailed gas supply to its
existing customers in order to take
commercial advantage of the supply
shortages (and higher prices) at the
time. It was said that this is much less
likely to happen today because there is
much more wholesale competition in
the market.!
The market now reacts very quickly to
a supply disruption. The EMF is
working well.
Not discussed or raised as an issue!
If contingency is to be improved, this
should be done through making used
of the existing EMF arrangements
better (communication is imperative)
If one producer goes down, other
producers will “spin” their plant.
Produce interruptible supply, then sign
up short term contracts with the
producer experiencing the disruption
Retailers go to customers to see
whether they can reduce demand
Gas purchased through short term
contracts is much cheaper than gas
available through long term take or pay
contracts. Short term gas is about half
the price. !
Shippers “enforced” to only take what
they are contracted to do
Producers pack gas in the DBNGP
pipeline (e.g. pack gas as insurance in
response to a cyclone).
There is some debate about whether
the EMF should be activated earlier in
response to potential supply problems!
Capacity of market to respond to a
major gas plant failure (e.g KPG out
for 3 months)!
Retailers were of the view that the
market is well positioned to meet any
supply disruptions associated with
processing plants.
Primarily because there are several
There are two types of supply
disruptions – one is a total loss of gas,
e.g. rupture of DBNGP (this constitutes
a true emergency). The other is a
lesser form of disruption and would call
for rationing gas between retailers,
Loss of KPG for 3 months would put a
strain on the system but not disastrous.
Gas users (including retailers) have
diversified their supply portfolios.
If gas producers were required to
Page 56 of 60
Loss of the KGP would no longer be
disastrous
Small use customer gas consumption
accounts for just 5% of gas used, so
should not be a problem finding
new producers since 2008. The current either through regulation or through a
spare capacity in the state is sufficient market mechanism.
to replace the total loss in supply from
the KGP or any other individual supply
point.
!
Synergy noted it has 90 TJ/d of gas
available for a period of 30 days from
Mondarra as a buffer.
Retailers also have the options of gas
trading, fuel switching and possibly
curtailment to large customers as a last
resort. !
Capacity of market to respond to a 7
day failure in DBNGP!
Contingency measures currently
adopted by retailers!
reserve capacity for retailers (as a
contingency measure) this would
involve a cost, but the cost would be
low because there is a lot of spare
production capacity.
enough gas to meet this demand.
In the event of a major pipeline
disruption there is not much in the way
of contingency options for retailers.
Major retailers have now got a wider
portfolio of options (than in 2008) – e.g.
There is clear evidence of Devils Creek flexible contracts with suppliers and
‘backfilling’ supply shortages when
customers; trading on the short-term
Varanus Island shut down in 2015 due market.
to a cyclone.!
Synergy now has access to Mondarra
storage!
Failure of the DBNGP is a very low
probability. It is much more likely that a
gas production plant will fail. If the
DBNGP did rupture south of Mondarra,
this would cause very big problems.
Truly an emergency situation that no
contingencies could effectively cover.
There would be minimal line pack to
draw on this far south and no gas
would be able to be drawn from
Mondarra.!
DBNGP is most vulnerable along the
unlooped section of the pipeline
between compressor stations (CS) 7
and 8 and between 9 and 10.
Producers sell gas. The transmission
of gas down the pipeline needs to be
negotiated separately with a pipeline
operator.
A 400-500 TJ/d reduction would have
a significant impact on the major
retailer (but negligible impact if just 200
TJ/d was disrupted because electricity
generators would be curtailed first)
Producers do have arrangements with
pipeline operators to ensure that
capacity of the pipeline is available
(balancing and reconciliation function).
Measures include
“As an operator of a gas distribution
network, we don’t want to be exposed
to the risk of a retailer not having
sufficient diversification of supply.”
There may be a risk that retailers will
curtail customers instead of actioning
other options (that are potentially more
costly to the retailer but that will be
better for customers).
Not discussed or raised as an issue!
•
Gas trading – short term market
•
Storage banking (through
contracts with shippers)
•
Fuel switching within the retailer’s
own business operations
(reallocating gas out of electricity
production for example)
•
Options contracts with suppliers
and large users (including
customers served by the retailer)
•
•
Storage in Mondarra
Curtailment of gas to large
customers.
All three retailers consulted viewed
Mondarra as “expensive insurance”!
Most of the brunt of a supply disruption
would be borne by large use customers
The producer consulted could not
Small use customer demand would still assess the risk or impact of DBNGP
failing.!
be able to be supplied in the scenario
that DBNGP went down for 8 days. !
PUO hasn’t had to consider legislative
intervention to manage a supply
disruption but has the power to do so
through the EMF. If the DBNGP was at
risk of becoming depressurised, this
scenario may trigger legislative
intervention.!
The market is served with excess
supply. The challenge is how to get
orderly access to in a supply disruption
(given limited wholesale price
transparency and volumes in line pack)
Trading platforms now exist but are
illiquid and don’t have sufficient
prudential oversight – so not trusted by
the major gas producers as a vehicle to
sell gas.!
Another operator noted that the market
is undervaluing Mondarra as an option
for managing supply disruptions
because retailers are constrained in
what mitigation costs they can pass
onto small use customers (through
regulation) and there is the option to
call ‘force majeure’, which imposes
costs on customers that do not impact
Page 57 of 60
on the retailer.!
Transparency of market information
(prices, volumes, disruptions)!
The market is very transparent for
Not discussed or raised as an issue!
those who are active participants in the
market.!
One producer noted that the WA
market would benefit from having
better price signals!
The GBB is effective at giving advance
warning of pipeline difficulties.
There is insufficient transparency
around wholesale prices and this is
impeding efficient investment decisions
(in response to changes in supply and
demand)
Line pack volumes are not transparent.
!
Curtailment processes in an
emergency scenario!
Retailers have curtailment policies and
processes in place should a disruption
arise, but these processes are not
uniformly consistent across all retailers
(a view was expressed that it would be
beneficial to get consistency).
Small use customers are more at risk
from curtailment to electricity
production (due to a gas disruption)
than curtailment of direct gas supply.
DBP has curtailment provisions written Not discussed or raised as an issue!
in customer contracts if CS 9 had to be
closed. This sets up priority to some
customers over others.
Possibly a need for an independent
body who would have authority to
manage the curtailment process and
determine who pays.
DBP curtails shippers proportionate to
their capacity holdings, except for one
large customer which has top priority.!
Need greater oversight of retailer
decision to curtail supply to customers
as opposed to going to market to buy
gas. !
!
Source: Consultations with stakeholders
Page 58 of 60
C
Cost of curtailment estimation method
This appendix sets out the approach that has been applied to estimate the welfare loss
incurred by large industrial and commercial gas customers as a result of the
curtailment of supply to these customers by gas retailers in order to maintain supply to
small-use customers in the event of a gas supply disruption.
The economic impact of a temporary disruption to gas supply can be estimated by
calculating the change in consumer surplus (area under the demand function) bounded
by Q1 (the existing amount of gas consumption) and Q2 (the amount of gas delivered
when supplies are rationed due to a disruption).
This method requires the following data inputs:
•
current aggregate gas consumption by customers subject to curtailment
•
current gas price paid by customers subject to curtailment
•
change in aggregate volume of gas supplied to curtailed customers
•
price elasticity of demand for gas for curtailed customers (denoted by
).
If we assume a constant price elasticity of demand (i.e. price elasticity is constant for all
levels of demand), the equation for calculating the change in consumer surplus (V)
from the curtailment of gas supply due to a supply disruption (Q1 reduced to Q2) is:
!
!
!
!! ×!!!
!!
!!
!! =
× !! ! − !! !
1
1−
!
The welfare loss as a result of a supply curtailment is lowest in situations where
demand for gas is price elastic (i.e. quantity demanded is very responsive to changes in
price). Conversely, the welfare loss for curtailed customers is greatest when demand is
price inelastic. In this case, the lower the capability of larger customers to switch to
alternative fuels, the less elastic is demand and subsequently the greater is the welfare
loss from a supply curtailment.
The calculation of V is shown graphically in the figure below.
Page 59 of 60
Figure C.1 Graphical representation of welfare loss through curtailment of gas
supply
Price
consumer surplus
foregone (V)
P1
Q2
Q1
Quantity
!
Source: Synergies Economic Consulting
The formula for calculating the welfare loss V produces non-linear estimates for V with
progressively higher volumes of curtailment. This is consistent with an increasing
marginal value for the gas as scarcity increases. The welfare loss function is suitable for
estimating welfare loss caused by marginal changes in gas supply. However, because
of simplifying assumptions about the functional form of the demand function, it is not
suitable for estimating very large quantities of curtailment (for example, where more
than 70 per cent or more of consumption is curtailed). For this reason, Synergies has
capped the unit cost of curtailment to $33.83 per GJ, which is the average welfare loss
(per GJ) based on curtailment of 40 TJ per day, a demand elasticity value of -0.4 and a
P1 price of $6 per GJ.
Page 60 of 60