Assessment of Requirement for Gas Contingency Service Obligations

Transcription

1 Assessment of Requirement for Gas Contingency Service Obligations Final Report to the Public Utilities Office May 2015 Synergies Economic Consulting Pty Ltd

2 Disclaimer Synergies Economic Consulting (Synergies) has prepared this report exclusively for the use of the party or parties specified in the report (the client) for the purposes specified in the report (Purpose). The report must not be used by any person other than the client or a person authorised by the client or for any purpose other than the Purpose for which it was prepared. The report is supplied in good faith and reflects the knowledge, expertise and experience of the consultants involved at the time of providing the report. The matters dealt with in this report are limited to those requested by the client and those matters considered by Synergies to be relevant for the Purpose. The information, data, opinions, evaluations, assessments and analysis referred to in, or relied upon in the preparation of, this report have been obtained from and are based on sources believed by us to be reliable and up to date, but no responsibility will be accepted for any error of fact or opinion. To the extent permitted by law, the opinions, recommendations, assessments and conclusions contained in this report are expressed without any warranties of any kind, express or implied. Synergies does not accept liability for any loss or damage including without limitation, compensatory, direct, indirect or consequential damages and claims of third parties, that may be caused directly or indirectly through the use of, reliance upon or interpretation of, the contents of the report.

3 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

4 Modelling method and assumptions 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

5 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

6 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

7 Contents Executive Summary 3! 1! Introduction 9! 1.1! Background 9! 1.2! Project objectives 9! 1.3! Organisation of this report 11! 2! Overview of approach 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! Page 7 of 60

8 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

9 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 PwC 3 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

10 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

11 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

12 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 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

13 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

14 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

15 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

16 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

17 3.2 Capacity of the market to respond to disruption 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, 26 th March Western Australian Government, Office of Energy (2010) Gas Tariffs Review Interim Report, March 2010 Page 17 of 60

18 small-use customers. 9 The costs imposed on large customers from this action were not compensated Developments 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 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 NIEIR forecasts Adapted from: IMO. (2014). Gas Statement of Opportunities December 2014, p. 9, Independent Market Operator (2014) Gas Statement of Opportunities December ibid 14 DomGas Alliance (2013) WA Domestic Gas Market Outlook, Final, February 2013 Page 18 of 60

19 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 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 IMO (2014) Gas Statement of Opportunities December 2014, p Page 19 of 60

20 Gas storage The Mondarra Gas Storage Facility (Mondarra), which is owned and operated by APA Group, was completed in 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 See; 19 WA Independent Market Operator. (2014). Gas Statement of Opportunities January Page 20 of 60

21 It is estimated that there are at least 60 active bilateral gas supply agreements 20 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 gastrading 23. 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 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 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 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 Page 21 of 60

22 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 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; 25 IMO (2014) SWIS Electricity Demand Outlook, June 2014, p Ibid, p Ibid, p IMO (2014) SWIS Electricity Demand Outlook, June 2014, pp Page 22 of 60

23 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 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; ct.aspx 30 WA Department of Finance website. Gas Services Information Project Emergency Management Facility FAQ. See; Management-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; Management-Facility-FAQ-(Approved)-21-January-2013.pdf. Page 23 of 60

24 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 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 Page 24 of 60

25 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

26 customers located south of the rupture point if the supplier is located north of the rupture point. 3.4 Contingency arrangements currently held by retailers 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 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 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 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 Page 26 of 60