CHAPTER 6 - GAS NETWORK PERFORMANCE AND FORECASTS

Transcription

1 CHAPTER 6 - GAS NETWORK PERFORMANCE AND FORECASTS 6.1 Summary This chapter provides information about forecast demand, and the gas Declared Transmission System s (gas DTS) adequacy to meet current demand, as well as including details about committed gas DTS augmentations, compressor strategies, and the potential impact of gas plant outages. The chapter also provides some context for Chapter 7, which includes information about the forecast development of the gas DTS and increasing gas powered generation (GPG) demand. The gas DTS was able to meet the peak day demand for 2010, with some spare capacity remaining. Peak day demand is weather dependent, however, and weather conditions on the day were milder than the forecast conditions used for network planning. The 2010 peak day occurred on 29 June 2010, with a system demand of 1,167 TJ, and GPG demand of 24 TJ, giving a total demand of 1,192 TJ. To meet demand and linepack requirements, 1,207 TJ was injected into the gas DTS, compared with a maximum system capacity of 1,353 TJ (for a simplified set of assumed conditions). Total demand was 222 PJ for the 12 months to 31 December 2010, a decrease of 4.6 PJ from This reflects a fall in GPG demand from 17.7 PJ to 7.6 PJ, partially offset by an increase in system demand, from PJ to PJ. This is higher than the system demand forecast for 2010 of PJ, and similar to the high economic growth system demand forecast for 2011 of PJ. Gas market supplies totalled PJ for the 12 months to 31 December A total of 60 TJ (109 tonnes) of liquefied natural gas (LNG) was scheduled and vaporised over this period, a significant decrease from 2009 largely attributed to decreased GPG demand and milder weather. Gas DTS demand forecasts (published in the 2010 VAPR Update) suggest that demand (system and GPG) will increase by 19.8% from 2011 to 2020, reflecting a significant growth in GPG demand, which is expected to increase from approximately 11.2 PJ/yr in 2010 to 42.1 PJ/yr by 2020 (based on the assumption that a carbon price takes effect in 2013/14). In 2011, two compressor packages at Wollert were commissioned and the pipeline between Wollert and Euroa was upgraded. With the completion of the Springhurst compressor upgrade and a new compressor station at Euroa (committed by winter 2012), this will increase Northern zone capacity, and support increased export capability. Other committed augmentations include a Sunbury Lateral Loop by mid AEMO 2011 Gas network performance and forecasts 153

2 VICTORIAN ANNUAL PLANNING REPORT 6.2 The Victorian gas network The gas Declared Transmission System The gas Declared Transmission System (gas DTS), which is Victoria s shared gas transmission network, comprises pipelines extending from Longford in the east of Victoria, across to Portland in the south west, and northwards to Culcairn in New South Wales. The main gas DTS pipelines include the: Longford Melbourne pipeline (Longford Dandenong Wollert) South West Pipeline (SWP) (Iona Geelong-Brooklyn) Northern System (Wollert Barnawartha Culcairn), 37 and Western Transmission System (WTS) from Iona to Portland (integrated into the gas DTS in 2003). The gas DTS receives gas via the following system injection points: Longford and VicHub both located at Longford. Gas is supplied from the Bass Strait gas fields and also flows to the gas DTS from the Eastern Gas Pipeline (EGP). BassGas located at Pakenham with gas supplied from the Yolla gas field. Iona, Otway and SEA Gas all located near Port Campbell. Gas is supplied from the Casino, Minerva, Thylacine and Geographe gas fields and the Underground Gas Storage (UGS) facility. Culcairn located in New South Wales. Gas can flow between the DTS Northern System and the New South Wales system at this point. The Liquefied Natural Gas (LNG) facility located at Dandenong. A diagram of the gas DTS pipelines can be found in the fold-out section at the back of the VAPR. For more information on current network infrastructure and capabilities, see Appendix D. For more information about gas transmission network development, see Chapter System capacity The modelled maximum individual capacities of the gas DTS pipelines are as follows: The Longford to Melbourne pipeline capacity is 1,030 TJ/d, which can be met by Longford injecting 970 TJ/d and BassGas injecting 60 TJ/d; or any other combination. The SWP pipeline capacity is 353 TJ/d. The New South Wales interconnect capacity is 92 TJ/d for import. The individual pipeline capacities have been determined by modelling simulations specifically set up to achieve the individual pipeline capacity. The Culcairn import capacity has been modelled to be 92 TJ/d, based on operation of the Young (Wagga Wagga) compressor and Springhurst compressor without the Wagga Wagga loop. The Wagga Wagga loop will increase Culcairn import capacity and this increased capacity will be reported in the November update. All modelling includes compressor fuel. 38 Due to transmission system constraints, however, total gas DTS pipeline capacity cannot be determined by simply summing these capacities. Instead, a model is used that determines capacity for a number of scenarios Including the New South Wales interconnect, which comprises the section from Barnawartha to Culcairn. The modelling software calculates the fuel required at each compressor station based on the operating power of the station. Therefore, fuel is a demand at each operating compressor station and the calculated pipeline flows include fuel transportation. Injections include system demand plus compressor fuel. 154 Gas network performance and forecasts AEMO 2011

3 The maximum gas DTS system capacity is 1,353 TJ/d under a simplified scenario where: New South Wales interconnect (Culcairn) flow is assumed to be zero there is no GPG demand and LNG injection is zero Iona operates at up to 9,500 kpa, and only the capacity of the gas DTS east of Iona is represented (therefore excluding the WTS and its demand, which is in the range of 12 TJ/d to 18 TJ/d). Appendix D, Section D.1.3 provides: capacity modelling results for this scenario and for different levels of imports and exports on the New South Wales interconnector; and provides modelling results for Iona injection capability on low demand days. 6.3 Gas demand This section presents historical and current information about system supply and demand, and demand for GPG and export. Unless otherwise stated, system demand refers to demand from: residential, small commercial and industrial customers nominally consuming less than 10 TJ of gas per annum (Tariff V); and large commercial and industrial customers nominally consuming more than 10 TJ of gas per annum (Tariff D). System demand is separate from GPG demand due to different demand characteristics. Currently, Victorian GPG tends to be used for electricity peak demand power generation. Increases in Tariff V demand are driven by population growth, employment levels and household income, and are mitigated by improved gas appliance efficiency, increased reverse cycle air conditioner usage for heating, and reduced water heating demand due to lower water usage. Factors affecting Tariff D demand include building cycle sensitivities, increased competition from overseas imports in the manufacturing sectors, natural gas-fired cogeneration and tri-generation by commercial and industrial customers, and responses to potential future carbon costs in the energy sector. Current and historical GPG gas consumption correlates strongly with the need for capacity support on an annual basis. GPGs operate as capacity support when conventional coal-fired generators are unavailable due to maintenance or there are low levels of intermittent generation, such as from hydroelectricity. However, peak day GPG consumption correlates to days of peak electricity demand with minimal contribution by intermittent generation. In the future, it is expected that GPG will run at higher load factors, not only providing capacity support, but also operating as intermediate or baseload generation. Exports, which can only occur at Culcairn, Iona/SEA Gas 39, BassGas 40 and VicHub, are also treated separately. This section addresses the requirement within NGR Rule 323 to publish information about: annual gas power generation demand available and prospective supply and the source of that supply, and mismatches between supply, demand, and capacity. The requirement to publish annual, monthly, peak day, and hourly demand forecasts was met in 2010 by publication of the 2010 VAPR Update in November 2010, which included the latest demand forecast information, and is available from the AEMO web site. 41 Key elements of the forecasts are presented in Section SEA Gas exports are financial only. Financial exports are quantities of gas that are scheduled for export, but are netted off against an injection (at the same point) such that the export never exceeds the injection. Physical quantities of gas cannot be exported due to the current configuration at SEA Gas. The export available from BassGas can occur when the BassGas plant is offline as it is dependent on demand and is not bid for. Excess gas moves through the a custody transfer meter (CTM) and is used locally downsteam outside of the gas DTS. This export is uncontrollable demand and therefore is not bid for within the Declared Wholesale Gas Market. AEMO 2011 Gas network performance and forecasts 155

4 VICTORIAN ANNUAL PLANNING REPORT The 2011 forecasts will be published in the 2011 Gas Statement of Opportunities (GSOO) in November Actual peak day demand Total demand refers to the sum of system demand, GPG demand, and exports. System demand refers to demand from Tariff V and Tariff D customers excluding GPG. See the 2010 VAPR Update (available from the AEMO website) for more information about Tariff V and Tariff D demand. The 2010 peak day occurred on 29 June 2010, with a system demand of 1,167 TJ. This was the coldest day in the 2010 winter on an effective degree day (EDD) basis, with an EDD of 14.10, falling short of the current 1 in 2 and 1 in 20 year weather standards of and 16.80, respectively. This compares with the 2009 VAPR Update s peak day system demand forecast for 2010 of: 1,181 TJ for a 1 in 2 peak day on a day with an EDD of 14.55, and 1,296 TJ for a 1 in 20 peak day on a day with an EDD of Table 6-1 lists the breakdown of demand for the 2010 peak day. The table shows that there was no export demand at any of the export withdrawal locations on the peak day. Table 6-1 Peak day demand, 2010 (TJ/d) Demand Source 29 June 2010 Percentage of Total System demand 1, GPG Iona a Bass Gas Export Culcairn SEA Gas VicHub Total demand 1, a. Iona withdrawals are delivered to the Underground Gas Storage (UGS) facility, or exported to South Australia. Figure 6-1 shows a comparison of the peak day hourly demand profile with a more typical hourly demand profile. The peak day in this graph represents a 1 in 20 day, a record which occurred in 2007; and the typical day represents a roughly 920 TJ demand day. 42 On a typical winter peak day, demand picks up in the morning after 6:00 AM due to residential area heating, water heating and industry start-up. Demand for gas heating increases again from 4:00 PM and declines by 12:00 AM (midnight). The graph also shows that on a peak day between 9:00 AM and 3:00 PM, demand in the system remained constant at a fairly high level, compared to the demand decreasing for a typical day. With consistent injection at injection sources, linepack would deplete further on the peak day, whereas the system could have regained some linepack during that period of time on a typical day TJ represents a typical demand day for winter. 156 Gas network performance and forecasts AEMO 2011

5 Figure 6-1 Peak day/typical hourly system demand profile comparison (TJ/hr) AEST Hourly system demand (TJ) Time Peak day system demand + GPG Peak day system demand Typical day system demand Actual annual demand Total demand 43 was PJ for the 12 months to 31 December 2010, with PJ (approximately 59%) of this demand occurring during the winter peak period (May to September). This compares with a total demand in 2009 of PJ, PJ of which (approximately 55%) occurred during the winter peak period. Table 6-2 lists the breakdown of demand in 2010 for the year and for the winter period. Table 6-2 Annual demand, 2010 (PJ) Demand Source 12 Months to December 2010 (PJ) Percentage of Total May to September 2010 (PJ) Percentage of Total System demand GPG Iona a Bass Gas Export Culcairn SEA Gas VicHub Total demand a. Iona withdrawals are delivered to the Underground Gas Storage (UGS) facility, or exported to South Australia. 43 Total demand for the period comprises system demand, Iona withdrawals (and exports), GPG demand, and other exports. AEMO 2011 Gas network performance and forecasts 157

6 VICTORIAN ANNUAL PLANNING REPORT System demand System demand for the 12 months to 31 December 2010 was PJ (approximately 95% of the total demand). This compares with the system demand in 2009 of PJ (approximately 90% of total demand). System demand covers the industrial, commercial, and residential sectors (Tariff D and Tariff V). See Chapter 7, for more information on GPG demand. Export demand Export demand for the 12 months to 31 December 2010 was 4.01 PJ (approximately 1.7% of the total demand). This compares with export demand for the 12 months to December 2009 of 4.35 PJ (approximately 1.9% of the total demand). Exports represent actual physical flows from the gas DTS, either via an interconnect or into the UGS facility. Total exports for the period were: 3.85 PJ via Culcairn (down from 4.23 PJ in 2009), showing a moderate change from PJ via BassGas (equal to 0.08 PJ in 2009), showing no change from PJ via VicHub (down from 0.08 PJ in 2009), showing a decrease due to market factors and operating conditions at Longford, and 0.08 PJ via Iona (up from 0.00 PJ in 2009), showing insignificant Iona exports for Gas supply Actual peak day supply The 2010 peak day occurred on 29 June 2010, with total supply (including LNG) of 1,207 TJ was injected into the DTS to meet demand and linepack requirements. The 14.9 TJ difference between demand and supply on this day was due to linepack changes over the course of the day. Table 6-3 lists the breakdown of supply in 2010 for the peak day. Table 6-3 Peak day supply, 2010 (TJ/d) Injection Point (TJ/d) Percentage of Total Longford VicHub BassGas Total Longford, VicHub and BassGas Iona UGS SEA Gas Otway Total Iona and SEA Gas Culcairn Total (excluding LNG) LNG a Total (including LNG) % a. This represents scheduled LNG only. 158 Gas network performance and forecasts AEMO 2011

7 6.4.2 Actual annual supply Gas market supplies totalled PJ for the 12 months to 31 December Longford and VicHub supplies were PJ in 2010 (approximately 70.9% of total supply). This compares with PJ in 2009 (approximately 66% of total supply). BassGas supplies were 13.0 PJ in 2010 (approximately 5.8% of total supply), compared to 17.2 PJ in 2009 (approximately 8.0% of total supply). A total of 3.09 PJ of LNG was injected into the DTS over Only 0.06 PJ (equal to 60TJ and equivalent to 1,099 tonnes), however, was scheduled and vaporised according to market need. This represented a significant decrease in the scheduled quantity of LNG from 2009, and is largely attributed to the decrease in GPG demand and milder weather conditions resulting in lower demand. Table 6-4 lists the breakdown of supply in 2010 for the year and for the winter peak period. Table 6-4 Annual supply, 2010 (PJ/yr) Injection Point 12 Months to December 2010 Percentage of Total May to September 2010 Percentage of Total Longford VicHub BassGas Total Longford, VicHub and BassGas Iona UGS SEA Gas Otway Mortlake Total Iona, SEA Gas and Otway Culcairn Total (excluding LNG) LNG a Total (including LNG) a. This represents total LNG being scheduled LNG and non-scheduled LNG. Scheduled LNG was 0.06 PJ for the year and 0.05 PJ for winter. 6.5 Demand and supply comparison Figure 6-2 shows the components of demand and supply for the 12 month period from January to December The left bar for each month shows system and GPG demand and exports, and the right bar shows supply by injection point. AEMO 2011 Gas network performance and forecasts 159

8 VICTORIAN ANNUAL PLANNING REPORT Figure 6-2 Monthly demand and supply comparison, 2010 (PJ/month) Monthly supply and demand (PJ) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year System Demand GPG Total Export Longford VicHub BassGas Iona SEA Gas Otway Mortlake Culcairn LNG 6.6 Gas demand forecasts This section presents a summary of the 2010 gas system demand 44 and GPG forecasts, which were prepared for AEMO by the National Institute Economic and Industry Research (NIEIR), and published in the VAPR Update in November The 2010 VAPR Update, available from the AEMO website, provides an overview of the annual gas system demand forecast inputs and the forecast approach. The report includes: annual and monthly gas system demand forecasts for GPG demand forecasts for peak day and peak hour gas system demand forecasts for export demand forecasts (and export levels) gas forecast methodologies key Victorian and Australian Government energy policies influencing gas demand growth gas customer survey results, and a comparison of the 2009 and 2010 VAPR Update gas peak day and annual system demand forecasts for the period System demand refers to withdrawals through gas DTS Custody Transfer Meters (CTMs), including gas used for compressor and heating fuel, but excluding withdrawals for GPG and LNG storage and at the Eastern Gas Pipeline, SEAGas / Iona, Lang Lang and Bass Gas. Distribution losses are implicitly included in the forecasts and transmission losses are negligible and are assumed to be zero. 160 Gas network performance and forecasts AEMO 2011

9 A VAPR Update report will not be published in Instead, AEMO will prepare an updated set of gas system demand forecasts and GPG demand forecasts for publication in the 2011 Gas Statement of Opportunities (GSOO) by the end of November These forecasts will replace the longer-term forecasts from the VAPR Update and will not reflect the latest winter data. The GSOO will be available from AEMO s website. In addition, AEMO will publish the Victorian gas forecasts for 2012 electronically on the AEMO website (also by the end of November), which will include an updated set of system demand, GPG demand and LNG forecasts taking into account the latest winter data. Refer to Appendix B for information about the methodologies and assumptions used to develop the gas demand forecasts, monthly system demand forecasts, monthly peak day system demand forecasts, peak hour system demand forecasts, gas export demand forecasts, and system withdrawal zone gas demand forecasts gas demand forecasts The main changes since the 2009 forecasts include a more positive economic outlook in view of a stronger recovery from the global financial crisis, the delayed implementation of carbon policy, and a number of small and medium-sized cogeneration plants under consideration by major gas customers in the Victorian gas DTS area. These changes generally involve the following: Annual system demand (total system demand excluding GPG) is now expected to reach PJ/yr in 2019, compared to the 2009 forecast of PJ/yr by Residential demand (Tariff V) is now forecast to be PJ/yr in 2019, compared to the 2009 forecast of PJ/yr by Commercial and industrial (Tariff D) demand is now forecast to be 86.7 PJ/yr in 2019, higher than the 2009 forecast of 83.8 PJ/yr by GPG demand on the DTS is forecast to increase to 42.1 PJ/yr by 2020, approximately 3.7 times the 2010 level. Annual gas demand forecasts Figure 6-3 provides an overview of the annual system demand and GPG demand forecasts. These forecasts exclude Iona withdrawals and exports; and are made for the low, medium, and high economic growth scenarios. The annual average growth rates of system and GPG gas demand for the forecast period are 0.5%, 2.0%, and 4.1% per annum for the low, medium, and high economic growth scenarios, respectively. AEMO 2011 Gas network performance and forecasts 161

10 VICTORIAN ANNUAL PLANNING REPORT Figure 6-3 Annual system demand and GPG gas demand forecast, (PJ/yr) Forecast demand (PJ/yr) Year System Demand (low) GPG(low) System Demand(medium) GPG (medium) System Demand (high) GPG (high) Forecasts suggest that gas demand (system and GPG) on the Victorian gas DTS will increase by 19.8% from 2011 to This represents significant growth in GPG demand under the assumption that carbon prices will take effect in 2013/14, which is expected to increase from approximately 11.2 PJ/yr in 2010 to 42.1 PJ/yr by System demand is expected to increase 5.1% by 2020 at the average annual growth rates of 0.55% for the medium case. Residential (Tariff V) demand is forecast to remain in line with population and household income growth, increasing 7.1% by 2020 at the average annual growth rates of 0.77% for the medium case. Commercial and industrial (Tariff D) demand is expected to increase 2.0% by 2020 at the average annual growth rates of 0.23% for the medium case. Peak day gas system demand forecasts Table 6-5 shows the 1 in 2 and 1 in 20 peak day system demand for the medium economic growth scenario for the forecast period (excluding GPG demand, Iona withdrawals and exports). The actual peak day system demand in 2010 was 1,167 TJ/d. This is lower than the 1 in 2 forecast of 1,183 TJ/d. The annual average growth rates for the medium economic growth scenario for the forecast period are 0.64% and 0.65% per annum for the 1 in 2 and 1 in 20 peak day forecasts, respectively. Peak day growth rates are forecast to be higher than annual system demand growth rates due to the temperature-sensitive component of residential gas demand, which increases with population growth, rather than in response to economic factors. 162 Gas network performance and forecasts AEMO 2011

11 Table 6-5 Peak day gas system demand forecasts, (TJ/d) Average Annual Growth in 2 1,183 1,202 1,221 1,234 1,239 1,241 1,245 1,253 1,260 1,267 1, % 1 in 20 1,304 1,326 1,346 1,361 1,366 1,369 1,373 1,382 1,391 1,398 1, % 6.7 Committed augmentations As stated in the 2010 VAPR Update, APA Group has advised AEMO that it has committed to two new augmentations to the DTS, incorporating a commitment to install a: new compressor station at Euroa by winter 2012, which will be a bi-directional facility that can compress gas for exports north or imports south, and Sunbury Lateral loop by mid The current proposal is to provide a new DN500 (500 mm diameter) pipeline from the Brooklyn-Lara Pipeline (BLP) at Hopkins Road to the Sunbury branch pipeline at the Plumpton offtake point (T62-LV03). 6.8 Compressor investment Two dry seal 4500 kw compressor packages have been commissioned and tested at Wollert in Associated with these new compressors is the upgrading of the pipeline between Wollert and Euroa to allow operation up to 8,800 kpa which has been completed during Further work is under review at Brooklyn. The upgrade work is subject to the APA Group Access Arrangement. Table 6-6 lists the proposed upgrades to specific compressors. Table 6-6 Compressor strategy Compressor Station (CS) Compressor Nature of Upgrade Expected Completion Brooklyn CS BCS13 and BCS14 Two new 3,500 kw dry seal compressors to replace the 850 kw BCS6 and BCS8, and the 950 kw BCS7 and BCS9 compressors (proposed). Under review Wollert CS WCS4 and WCS5 Two new 4,500 kw dry seal compressors (completed) WCS6 A new 4,500 kw dry seal compressor to meet increasing demand (proposed). Under review Springhurst CS SCS1 Reconfigure existing 4,500 kw dry seal compressor for bi-directional compression (completed) Euroa CS ECS1 One new 4,500 kw dry seal compressor (proposed) AEMO 2011 Gas network performance and forecasts 163

12 VICTORIAN ANNUAL PLANNING REPORT 6.9 Plant outages and transmission system capacity Table 6-7 lists the potential high-level impacts from specific gas plant outages involving entire facilities. Table 6-7 Gas plant outage impacts Plant Brooklyn CS a Gooding CS LNG facility SCADA/Communication system Springhurst CS Wollert CS Outage Impact Constrains summer transport to Iona as contractual pressure at Iona would be breached if Iona does not inject. During winter, it minimises supply to the Ballarat and Sunbury pipelines, and possibly the GPG at Laverton. Limits Longford injections to approximately 760 TJ/d. Decreases the ability to maintain system linepack, potentially leading to curtailment. Requires the implementation of manual operation, reducing control effectiveness and impacting operational schedules. If Springhurst CS is not operating: Culcairn import capacity is reduced from 92 TJ/d to 60 TJ/d when Young (Wagga Wagga) compressor is operating, and Culcairn import capacity is reduced from 50 TJ/d to 35 TJ/d when Young (Wagga Wagga) compressor is not operating b. Decreases the transportation capacity from Wollert to Culcairn, further limiting gas exports to New South Wales. Also minimises supply to northern demand locations. a. CS = Compressor Station b. Both of these capacities assume that the Wagga Wagga loop is not in place (see Section 6.2.2). Maintenance schedules Annual maintenance schedules are generally the same from year-to-year. As a result, and in conjunction with the five-year maintenance forecast, AEMO expects the maintenance schedule for 2010 to apply for the forecast period. This information is available in Chapter 3, Section 3.4 and Section 3.5, of the 2010 VAPR Update published on the AEMO website. 164 Gas network performance and forecasts AEMO 2011