Gas Prices in Western Australia

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1 Review of inputs to the Wholesale Electricity Market Draft Report prepared for the Independent Market Operator February 2013

2 Reliance and Disclaimer The professional analysis and advice in this report has been prepared by ACIL Tasman for the exclusive use of the party or parties to whom it is addressed (the addressee) and for the purposes specified in it. This report is supplied in good faith and reflects the knowledge, expertise and experience of the consultants involved. The report must not be published, quoted or disseminated to any other party without ACIL Tasman s prior written consent. ACIL Tasman accepts no responsibility whatsoever for any loss occasioned by any person acting or refraining from action as a result of reliance on the report, other than the addressee. In conducting the analysis in this report ACIL Tasman has endeavoured to use what it considers is the best information available at the date of publication, including information supplied by the addressee. Unless stated otherwise, ACIL Tasman does not warrant the accuracy of any forecast or prediction in the report. Although ACIL Tasman exercises reasonable care when making forecasts or predictions, factors in the process, such as future market behaviour, are inherently uncertain and cannot be forecast or predicted reliably. ACIL Tasman shall not be liable in respect of any claim arising out of the failure of a client investment to perform to the advantage of the client or to the advantage of the client to the degree suggested or assumed in any advice or forecast given by ACIL Tasman. ACIL Tasman Pty Ltd ABN Internet Melbourne (Head Office) Level 4, 114 William Street Melbourne VIC 3000 Telephone (+61 3) Facsimile (+61 3) melbourne@aciltasman.com.au Brisbane Level 15, 127 Creek Street Brisbane QLD 4000 GPO Box 32 Brisbane QLD 4001 Telephone (+61 7) Facsimile (+61 7) brisbane@aciltasman.com.au Canberra Level 2, 33 Ainslie Place Canberra City ACT 2600 GPO Box 1322 Canberra ACT 2601 Telephone (+61 2) Facsimile (+61 2) canberra@aciltasman.com.au Perth Centa Building C2, 118 Railway Street West Perth WA 6005 Telephone (+61 8) Facsimile (+61 8) perth@aciltasman.com.au Sydney Level 20, Tower 2 Darling Park 201 Sussex Street Sydney NSW 2000 GPO Box 4670 Sydney NSW 2001 Telephone (+61 2) Facsimile (+61 2) sydney@aciltasman.com.au For information on this report Please contact: Mark Chatfield Telephone (08) Mobile m.chatfield@aciltasman.com.au Contributing team members Jackie Hamilton (08) j.hamilton@aciltasman.com.au

3 Contents Executive Summary iii 1 Introduction 1 2 Gas Commodity Prices Gas Price Limits Minimum Maximum Intermediate Gas Price Data Resultant Spot Gas Price Range 6 3 Gas Transmission Costs Standard Tariffs DBP Standard Shipper Tariff GGP Tariff Spot Gas Transport Tariffs Dampier to Bunbury Gas Pipeline Goldfields Gas Pipeline Conclusions on Gas Transport Tariffs 11 4 Load Factors 12 5 Carbon Imposts The Carbon Pricing Mechanism Gas Producer Imposts Gas Transport Carbon Cost Imposts 14 List of figures Figure 1 Spot gas price distribution 6 Figure 2 Gas price distribution curve fitting error analysis 7 List of tables Table 1 Key parameters of fitted spot gas price distribution 7 ii

4 Executive Summary As requested by the Independent Market Operator (IMO), ACIL Tasman has estimated the delivered cost of fuel to a peaking gas turbine in the SWIS for the financial year. The cost of gas has been estimated as having the 80% confidence interval range of $5.02 per GJ to $11.56 per GJ, with a fitted distribution curve mean of $7.99 per GJ. The cost of gas transport has been estimated as: for the South West (through the DBNGP), a log normal distribution 80% confidence interval range of $1.46 per GJ to $2.15 per GJ, with a log normal mean of $1.80 per GJ; for the Goldfields, a single price of $5.91 per GJ for transport in the Goldfields Gas Pipeline. For the marginal gas peaker, a load factor log normal distribution 80 per cent confidence interval of between 80 and 98 per cent centred on a log normal mode of 95 per cent would reflect the small but significant probability of load factor variation from the day ahead expectations. The log normal mean is 96 per cent. This load factor is applied to both the Goldfields and DBNGP transport costs, as well as to the spot gas prices. Since 2012 a cost on carbon emissions has applied in Australia. The gas producers, as well as gas pipeline operators in Western Australia are affected by the Clean Energy Act and require reimbursement from the gas users of the costs incurred under the legislation. For we have estimated a gas producer impost of $0.06/GJ of gas sold and a $0.03/GJ impost on gas transport on both Dampier to Bunbury and the Goldfields pipelines. These imposts are not included in the gas transport cost and prices shown above. Executive Summary iii

5 1 Introduction ACIL Tasman has been engaged by the Independent Market Operator (IMO) to: update information on the likely gas prices faced by gas fired electricity generators in the Western Australian Wholesale Electricity Market (WEM) in the financial year, to be used in the 2013 Energy Price Limits review, and determine the associated gas price range, gas transport cost and load factor to be included in the calculation of the Maximum Short Term Energy Market (STEM) Price. The Energy Price Limits are set for the WEM and include the Maximum STEM Price, which applies when non-liquid fuel is used by the highest cost peaking plant in the SWIS. The Maximum STEM Price must be determined for the highest cost peaking plant fuelled by gas. Accordingly, the gas fuel cost faced by the highest cost peaking plant is a key input to the determination of the Maximum STEM Price. According to clause of the Market Rules the IMO must annually review the appropriateness of the value of the Maximum STEM Price and Alternative Maximum STEM Price. Clause of the Market Rules determines that the Maximum STEM price must be set for the estimate of the short run marginal cost of the highest cost generating works in the SWIS fuelled by natural gas, where among other things: 1 the Heat Rate is based on a 40MW open cycle gas turbine heat rate at minimum capacity, expressed in GJ/MWh the Fuel Cost is the mean unit fixed and variable fuel cost for a 40 MW open cycle gas turbine generating station expressed in $/GJ. The Market Rules require the Energy Price Limits Review to consider a 40MW plant. The rationale for this is that these smaller units are likely to have higher average costs than larger units, hence the smaller unit can inform the maximum bound on costs. Power stations that potentially meet the test of the highest cost peaking plant fuelled by gas will be typically be small open cycle gas turbine plants operating in the SWIS that have high short run marginal costs. A number of generators closely approximate this potential requirement for the financial year, and include: 1 The Market Rules are available at Introduction 1

6 Pinjar GTs six dual fuel OCGTs of 37 MW each operated by Verve Energy Mungarra GTs three 37 MW gas fired OCGTs operated by Verve Energy Kwinana Swift GTs four 30 MW dual fuel OCGTs at Kwinana operated by Perth Energy. Parkeston GTs three 40 MW dual fuel units operated by Goldfields Power. Introduction 2

7 2 Gas Commodity Prices In the reviews conducted in previous years, ACIL Tasman recommended that the spot gas price be used for the calculation of Energy Price Limits in the WEM, as it provides a reasonable indication of the value of surplus gas being used by the marginal gas fired peaking plant sourced either from within a portfolio, or from purchases on the secondary market. The rationale behind this recommendation is that the spot gas price is effectively the opportunity cost for use of that gas. In particular, for the infrequent use of spare gas within a portfolio, the price of gas on the secondary market is the value in its next best use. This is economically efficient and for this reason the spot gas price is still considered as the relevant gas price for the 2013 Energy Price Limits review in the calculation of the Maximum STEM Price 2.1 Gas Price Limits The bounds of the spot gas price range can be set with a reference to a minimum price set by the selling prices prevailing in long term take or pay gas purchase contracts, and the maximum price that a purchaser would be willing to pay which could be set with reference to the alternative fuel price Minimum In its considerations ACIL Tasman used several recent public reports to determine the minimum gas price: Woodside s quarterly update in January which indicates that its average selling price into the domestic gas market is about $4.40/GJ. Since the North West Shelf venture members sell gas jointly, we conclude that this average price applies to the approximately 60% of the domestic gas volume they supply. The Department of Mines and Petroleum publication titled Western Australian Mineral and Petroleum Statistics Digest stated that the average price of gas sold into the DBNGP in Western Australia rose by five per cent in and averaged $4.20 per gigajoule. The average prices stated above are the result of long term, take or pay legacy contracts with a few major gas buyers, and it is difficult, if not impossible, to Gas Commodity Prices 3

8 buy spot gas at those prices in the short term. We are unaware of any material quantities of gas sold at prices below these averages in recent years Maximum The maximum spot gas price can be calculated with reference to the price of the substitute fuel, distillate. It is considered that a price set at 90% of the distillate equivalent in $/GJ, to retain some advantage for the generator to use gas rather than distillate, forms a reasonable assumption of the maximum spot gas price in the WEM. We used a current distillate price of $24.30/GJ (exclusive of GST and excise) delivered to a gas turbine station north of Perth in the calculation of the upper limit of the spot gas price. The distillate price was derived from the 2012 average Perth Terminal Gate Price (TGP) 4 of $1.38/litre to which $0.01/litre was added for transport to Pinjar. The GST and excise of $ /litre for year were then deducted before the price was converted to $/GJ. The 2012 historical TGP was considered adequate as the EIA forecasts of crude oil prices for 2013 and 2014 are flat Intermediate Gas Price Data In the determination of the spot gas price for ACIL Tasman used the two end points (minimum of $4.40/GJ and maximum of $21.90/GJ) calculated as described in 2.1 and several other price points which are described in this section. Even though attempts to facilitate spot gas sales in Western Australia resulted in existence of two spot market trading platforms, the volumes traded are very low and have limited significance in the scale of total gas sales. Energy Access Services Pty Ltd (Energy Access) was founded in The company mission was to meet the growing need for an independent, secure and efficient energy trading mechanism. A very well set up website (energyaccessservices.com.au) is available. According to the website, the Energy Trading Platform (ETP) enables trading members (natural gas buyers and sellers) to complete short term (up to 7 days) and medium term (up to 90 days) trades promptly, efficiently and securely. Long term trades are also accommodated, though the focus of the ETP commercial documentation is on short to medium term transactions. So far we are not aware of any trades occurring through this platform Gas Commodity Prices 4

9 The second trading platform is known under the name gastrading. It operates on both the DBP and the Goldfields pipelines where it manages the gas supply arrangements for several mine sites. It has developed a spot market for gas trading and even though its trades have grown considerably over the last couple of years, the trading volumes average only about 10 TJ/day 6. Over the last 12 months, the prices of the gas traded in this spot market ranged from $1.97/GJ to $10.43/GJ, with an average $5.37/GJ. The prices are moderate as they are a result of disposing of excess volumes from take or pay contracts and the arrangements are usually interruptible. There is an expectation of an upward shift in the prices due to future changes in some of the current contractual arrangements. Short term gas trades may also occur between the gas users who may try to rebalance their positions driven by the short term circumstances facing industries that are operating under long term gas purchase contracts. Apart from gastrading data, currently there is no publicly available information on the short term gas trades. ACIL Tasman held discussions with three parties involved in short term gas trading to gain some insights into the volumes or prices. The gas users indicated that currently the trades are very rare. Spot gas might be available from gas producers, however prices would not be low as they would take into account the future opportunity value of gas. With the implementation of the new Gas Bulletin Board (GBB) and Gas Statement of Opportunities (GSOO) scheduled for August 2013, there will be more information relating to short and near term natural gas supply and demand, and natural gas transmission in the State. The aim is to improve information transparency and facilitate the security, reliability, efficiency and competitiveness of the domestic gas supply market in WA. It is yet to be seen if the prices will be affected during the period. From discussions with gas users we concluded that it is unlikely that gas prices will change materially in the short to medium term. As other intermediate points, we have used data on gas prices that ACIL Tasman collected on assignments from several clients. This data was included in the Monte Carlo simulation described in 2.3 but it cannot be discussed here due to its confidential nature. There is anecdotal evidence of some spot gas becoming available at lower prices reflecting short term easing of the supply- demand balance due to reduced demand and increased supply from new gas projects as well as availability of gas from Mondarra storage coming on line during Gas Commodity Prices 5

10 2.3 Resultant Spot Gas Price Range In , gas on the spot market can either come from the producers of domestic gas, i.e. the North-West Shelf Joint Venture, Apache operated projects (Harriet, Spar, Reindeer) and from the BBHP operated Macedon project, or from large users reselling gas acquired under take or pay contracts. While the producers are likely to sell at similar prices, large users face higher opportunity costs in selling gas and will therefore demand higher prices. We approximated each potential seller s supply curve with a log-normal distribution with a specific mean and standard deviation. Other potential supply curves included were those derived from available spot market trading data and possible short term trades resulting from timing differences on new projects. In order to generate a compound price range, we conducted a Monte Carlo simulation randomly drawing prices from each supply curve. The number of prices drawn from each individual distribution was set by the anticipated relative contribution of each seller to total supply. The large producers' supply curves received higher weightings, users with gas to resell and spot market trades received lower weightings corresponding with the likelihood of the spot gas supply availability. This produced a single series with compound probabilities for each one cent price interval. The resulting price distribution, including curves fitted to the simulation output curve, is presented in Figure 1. Figure 1 Spot gas price distribution Probability (bin size = $0.1) 1.8% 1.6% 1.4% Simulated probability Fitted normal distribution Fitted lognormal distribution Fitted Gamma distribution 1.2% 1.0% 0.8% 0.6% 0.4% 0.2% 0.0% $/GJ Source: ACIL Tasman modelling Gas Commodity Prices 6

11 As depicted in Figure 1, three different curves were tested to represent the simulated data. Out of normal, lognormal and gamma distribution curves, the lognormal distribution offered the best fit as demonstrated by the error analysis presented in Figure 2. Figure 2 Error Gas price distribution curve fitting error analysis Normal distribution Lognormal distribution Gamma distribution Source: ACIL Tasman modelling The lognormal distribution curve was used to derive the characteristics of spot gas price distribution presented in Table 1. Table 1 Key parameters of fitted spot gas price distribution Parameter Mean Mode Source: ACIL Tasman modelling Value $ 7.99/GJ $ 6.80/GJ 80% lower bound $ 5.02/GJ 80% upper bound $ 11.56/GJ The above mean price is lower than that presented in the 2012 Review as a consequence of updated spot gas availability and price data points (as discussed in 2.2), resulting in a different Monte Carlo simulation outcome. Gas Commodity Prices 7

12 3 Gas Transmission Costs Transmission costs on both the DBNGP and the GGP are regulated by the Economic Regulation Authority under the National Gas Law. However, all contracts on the DBNGP are bi-lateral contracts negotiated outside the regulatory regime with tariffs agreed between DBP Transmission, the operator of the DBNGP, and shippers. In addition, most contracts on the GGP relate to uncovered expansions of the pipeline, and hence are at rates different to the reference tariffs. 3.1 Standard Tariffs DBP Standard Shipper Tariff The Access Arrangement sets out the basis for accessing spare uncontracted capacity on the pipeline. It contains a set of terms and conditions in the event that a prospective customer cannot agree on a service with DBP 7. Existing firm full haul capacity of the DBNGP is fully contracted to shippers under contracts negotiated outside the regulatory framework. The negotiated T1 Standard Shipper Contract used by the majority of existing shippers is a firm full haul service. Under the T1 Service, Shippers pay a Base T1 Tariff. That tariff is made up of the T1 Commodity Tariff and the T1 Reservation Tariff. The Base T1 Tariff as outlined in all shipper contracts (even those that commence after 1 January 2003), is the tariff as at 1 January $1.053/GJ. The Base T1 Tariff is then adjusted by a combination of: inflation based adjustments and adjustments to reflect the capital costs of expansions that were not factored into the original Base T1 tariff (called the Tariff Adjustment Factor). The adjustments are made following each expansion and the inflation based adjustments are made on 1 January of each year. The T1 tariff escalated at CPI until 1 January According to the DBNGP - Access guide (published on the DBP website in Oct 2011), the T1 Tariff was $ /GJ as at 1 January 2011 at 100 per cent load factor. The T1 tariff is escalated at CPI less 2.5 per cent from 1 January 2012 to 1 January The relevant CPI is that for All Groups Perth. The average escalated T1 tariff for the financial year is estimated to be around $1.55/GJ, assuming a 2.5% inflation rate. 7 Gas Transmission Costs 8

13 3.1.2 GGP Tariff While the ERA publishes rates for the GGP on its website, these are for the covered portion of the pipeline, and do not apply to the uncovered parts, which relate to subsequent expansions. Charges for typical gas transportation services are comprised of three components and vary depending on customer requirements, including load, point of delivery and contract duration. These, and the rates that typically apply, are: Toll charge of $ /GJ, capacity reservation charge of $ /GJ/km and throughput charge of $ /GJ/km. These rates are indexed with the Consumer Price Index (CPI, All Groups, average of the eight capital cities). The reference CPI base for the tariff is June 1997, which had a base value of The toll charge is applied to the maximum daily quantity of gas capacity (MDQ) reserved by the customer. The capacity reservation charge is multiplied by the pipeline length (in km) from the inlet point to the outlet point to derive the overall unit charge to be applied to the MDQ. The throughput charge is multiplied by the pipeline length (in km) to be applied to the actual quantity of gas delivered. In general, about 80% of the total unit charge is comprised of a toll charge and a capacity reservation charge. The throughput charge makes up the balance of the unit charge. That is, the toll charge and capacity reservation charge for each day is charged to customers on a take-or-pay basis, while the throughput charge is based on the actual quantity delivered. Other charges may include a 'used gas charge', 'nomination service charge', 'account establishment and maintenance charge', and other relevant charges detailed in the GGP s terms and conditions. After escalating the above tariffs and applying a factor to cater for pipeline distance of 1378 km to Kalgoorlie, a 100 per cent capacity tariff to Kalgoorlie would cost around $5.37/ GJ for the financial year. 3.2 Spot Gas Transport Tariffs Spot gas transport may come with the purchase of spot gas or may need to be sourced separately, either directly from the pipeline operator or from a third party which has spare volume in its contracted capacity during periods of low utilisation. Even though the spot capacity may be available at cost during the periods of low utilisation, a premium over the reference tariff would need to be paid during high demand periods, coinciding with the occurrence of STEM prices at the limit. Gas Transmission Costs 9

14 3.2.1 Dampier to Bunbury Gas Pipeline DBP offers spot capacity daily. Shippers are advised by between hrs WST of the quantity of spot capacity available for the next gas day. Shippers have until 1600 hrs of the current gas day to bid for the spot capacity available for the next gas day using the Customer Reporting System (CRS). The price for full haul and part haul spot capacity on the DBNGP from DBP is set by an auction process. In summary the process is as follows: Each day DBP Transmission publishes, for shippers, the amount of spot capacity available for the following day and the minimum price at which DBP Transmission is willing to provide that capacity. Typically the minimum price is 115 per cent of the 100 per cent load factor T1 tariff, with charges applied to the actual amount of capacity used on the day. Shippers then bid price/volume pairs. Spot capacity is then allocated to the highest priced bid, then the next highest, until the published quantity is allocated. Currently, with the pipeline having an excess of capacity, there is limited activity on the spot market and the spot capacity is generally sold at the minimum price. Our expectation is that this situation will continue during the financial year. Having excess pipeline capacity, contracted shippers are now willing to offer their capacity to third parties on spot basis. Typically this capacity is traded at the cost of the T1 tariff. The downward revision of load and demand forecasts in the latest Statement of Opportunities 8, coupled with the increased wind and coal plant capacity as well as availability of gas from Mondarra storage, mean that the excess of pipeline capacity will continue in the financial year Goldfields Gas Pipeline The Goldfields gas pipeline does not currently have any arrangements for spot transport in place. However, we understand that it would be possible for an existing shipper to gain access to limited volumes of spot capacity for a small premium above the existing indicative tariffs 8 Gas Transmission Costs 10

15 3.3 Conclusions on Gas Transport Tariffs During the high gas demand periods, the spot transport costs for the South- West for the financial year are anticipated to be at modest premium to the standard T1 tariff due to the current excess capacity on the pipeline. For the South-West in , $1.46 per GJ to $2.15 per GJ provides a log normal distribution 80 per cent confidence interval range for both full haul and part haul, around a log normal distribution mode of $1.74 per GJ. The log normal mean is $1.80 per GJ. For the Goldfields, a 10% premium inclusive single price of $5.91 per GJ provides an estimate of spot transport costs for the financial year, into Kalgoorlie, when available. Gas Transmission Costs 11

16 4 Load Factors For a marginal generator to be able to use spot gas, arrangements need to be made by 4 pm on a day prior to dispatch day. Both elements, the spot gas commodity as well as gas transport reservation would be 100 % take or pay. With the STEM being a day ahead market, with half hourly prices established by auction for the subsequent day, there is a risk of daily forecast volume error and this needs to be considered in the application of load factor to spot gas and transport trades. This risk can possibly be modified by the re-bidding process under the new Balancing Market regime in the WEM, but it may result in pricing outcomes for generators in which they are unable to recover the full cost of spot gas secured in advance. As such, there would still be some risk that the marginal gas peaker using take or pay spot gas did not get dispatched in accordance with expectations, given the need to make arrangements to purchase spot gas a day ahead. In this case, the load factor may not be 100 per cent. ACIL Tasman discussions with market participants did not indicate material changes to load factors resulting from the new balancing market. Hence we recommend that the load factors used in the previous year are used to establish price limits for the financial year. As stated in previous reports, a load factor log normal distribution 80 per cent confidence interval of between 80 and 98 per cent - centred on a log normal mode of 95 per cent - would reflect the probability of lower than expected spot gas utilisation. The log normal mean is 96 per cent. This load factor is applied to both the Goldfields and DBNGP transport costs, as well as to the spot gas prices. Load Factors 12

17 5 Carbon Imposts 5.1 The Carbon Pricing Mechanism In 2011 the Australian Parliament passed legislation (Clean Energy Act 2011) which introduced a tax on the emission of carbon (dioxide) by the largest emitters in the nation. The carbon pricing mechanism is an emissions trading scheme that puts a price on Australia's carbon pollution. The scheme became operational in July 2012 and applies to Australia's carbon emitters (called liable entities) which emit over 25 kilotonnes of carbon dioxide per annum 9. Under the mechanism, liable entities must pay a price for the carbon emissions they produce each year. This covers approximately 60 per cent of Australia's carbon emissions including from electricity generation, stationary energy, landfills, wastewater, industrial processes and fugitive emissions. At the end of each financial year, liable entities must surrender one carbon unit for every tonne of carbon dioxide equivalent (CO2-e) - that they have produced in that year. This creates economic incentives to reduce their pollution. There are two stages to the carbon pricing mechanism: Fixed price - the carbon price is fixed for the first three years. In 2012/13 it is $23 per tonne of carbon pollution, in 2013/14 it is $24.15 per tonne and in 2014/15 it is $25.40 per tonne. Liable entities can purchase units up to their emissions levels. Flexible price - from 1 July 2015 the price will be set by the market. Most units will be auctioned by the Clean Energy Regulator in the lead up to the flexible price. The number of units the Government issues each year will be limited by a pollution cap set by regulations. From July 2012 gas producers, as well as gas pipeline operators in Western Australia were affected by the Clean Energy Act and will require reimbursement from the gas users of the costs incurred under the legislation. 5.2 Gas Producer Imposts Carbon emissions during natural gas extraction and processing come from combustion emissions, which include stationary and mobile combustion sources and from fugitive emissions. 9 Carbon Imposts 13

18 Stationary combustion emissions include the emissions resulting from the combustion of fuels in boilers, furnaces, burners, heaters, and stationary turbines and engines, as well as the combustion of wastes in incinerators and flares. These sources account for most of carbon emissions. Fuel gas is estimated to comprise about 80% of total gas producer carbon emissions. Mobile combustion sources include combustion of fuels in ships, barges, trains, trucks, and aircraft. These emissions are much smaller than from stationary combustion sources. Fugitive emissions can occur from equipment leaks such as from seals, gaskets and valves. These are insignificant compared to combustion and process emissions. ACIL Tasman used several methodologies to estimate carbon intensity for the various domestic gas producers: The first method was based on the assumption that 5% of gas is used in the gas producer s plant and offshore facilities to transport and process the gas. Our calculations result in a carbon intensity of tco2/gj produced. This intensity requires an impost of $0.063/GJ of gas produced during the financial year. Another calculation of carbon intensity was based on the publicly available information gleaned from Woodside reports. Taking into account emission information in Woodside s quarterly update in January , published overall carbon intensity of 0.26 tonnes CO2e per tonne of hydrocarbon production 11, and the LNG production carbon intensity of 0.41 tonnes CO2e per tonne, the carbon intensity of domestic gas production was calculated to be in the range between and tonnes CO2 per GJ gas produced. This intensity would result in an impost of $0.052/GJ to $0.060/GJ in the period. ACIL Tasman s recommendation is that a value of $0.06/GJ is used as gas producer carbon cost impost. 5.3 Gas Transport Carbon Cost Imposts The gas pipeline operators serving the SWIS will pass on any carbon impost attributable to the operation of their pipeline whether incurred by the operator directly or by payment to any third party liable for the payment of carbon costs sustainable development report.pdf Carbon Imposts 14

19 The main source of carbon dioxide emissions is the system use gas, which is the gas consumed in the operation of the pipeline and includes gas used for compressor fuel, gas engine alternator fuel, heater fuel and increases to linepack. ACIL Tasman estimated the cost of carbon in the gas transport component on the basis of the information published in the Dampier to Bunbury Natural Gas Pipeline - Revised Access Arrangement Our calculations indicate an impost of about $0.03/GJ of gas transported through the DBNGP in the period. Our estimation was confirmed in discussions with DBP. Goldfields Gas Transmission utilises a methodology in which customer carbon costs are calculated by the addition of combustion (fuel gas) emissions and fugitive emissions. Combustion emissions are equal to the customer s fuel gas used x 51.33kg/GJ (Source NGERS Determination). Fugitive emissions are currently calculated by using method 1 of the NGERS Determination and are apportioned using the same method to apportioning a customer s fuel gas allocation. All emissions are charged at the Government s fixed price for carbon. We have calculated GGP carbon intensity on the basis of an assumption of 2% system use gas, derived using data from the Goldfields Gas Pipeline Access Arrangement Information 13. The calculated carbon intensity is tonnes CO2 per GJ gas transported. This results in the carbon cost impost for GGP at about $0.025/GJ, which is very similar to that of DBP at about $0.03/GJ Goldfields Gas Transmission Pty Ltd-Goldfields Gas Pipeline-Proposed Access Arrangement Information.pdf Carbon Imposts 15