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1 TECHNICAL GUIDE TO THE VICTORIAN GAS WHOLESALE MARKET JANUARY 2010

2 Disclaimer This document is made available to you on the following basis: (a) Purpose - This document is provided by the Australian Energy Market Operator Limited (AEMO) to you for information purposes only. You are not permitted to commercialise it or any information contained in it. (b) No Reliance or warranty - This document may be subsequently amended. AEMO does not warrant or represent that the data or information in this document is accurate, reliable, complete or current or that it is suitable for particular purposes. You should verify and check the accuracy, completeness, reliability and suitability of this document for any use to which you intend to put it and seek independent expert advice before using it, or any information contained in it. (c) Limitation of liability - To the extent permitted by law, AEMO and its advisers, consultants and other contributors to this document (or their respective associated companies, businesses, partners, directors, officers or employees) shall not be liable for any errors, omissions, defects or misrepresentations in the information contained in this document, or for any loss or damage suffered by persons who use or rely on such information (including by reason of negligence, negligent misstatement or otherwise). If any law prohibits the exclusion of such liability, AEMO s liability is limited, at AEMO s option, to the re-supply of the information, provided that this limitation is permitted by law and is fair and reasonable All rights reserved.

3 CONTENTS 1 Introduction 2 2 An overview of the Victorian Declared Wholesale Gas Market Background The role of AEMO Victorian gas market coverage The Declared Transmission System Injection and Withdrawal points Supply and Demand in the gas market Daily supply-demand Controllable injections and withdrawals AMDQ transportation rights The National Gas Rules 7 3 Participants in the Gas Market Participants in the market Participants indirectly involved in the market Registration Market consultative forums Gas market consultative forum Retail market consultative forum 11 4 Trading gas imbalances 12 5 Gas market processes 13 6 The Gas Market System Transportation and Market Manager WebExchanger SCADA Market Clearing Engine Metering and Settlements System Market Information Bulletin Board Demand Forecast System 15 7 Authorised Maximum Daily Quantity Authorised MDQ Authorised MDQ transfers AMDQ Credits Obtaining AMDQ Benefits of AMDQ Public Register of Spare Capacity 18 8 Gas scheduling An overview of the gas scheduling process Normal operating conditions Abnormal operating conditions Threats to system security System force majeure events and market suspension Administered price period Cumulative price threshold Gas Schedules Market participant inputs Market Bids Demand forecasts Injection hedge nominations Agency injection hedge nomination Accredited bid constraints AEMO s inputs Demand forecast overrides Supply and demand point constraints End-of-day linepack target Intra-day adjustments for injections or controllable withdrawals Other inputs Scheduling Outputs Pricing schedules Operating Schedules 30 9 The Metering process Metering installations Metering register Metering database Conversion to energy 31

4 CONTENTS CONTINUED 10 The Settlements process Imbalance payments The imbalance payment Concept Calculation of imbalance payments An example of imbalance payments Deviation payments The deviation payment concept Calculations of deviation payments An example of deviation payments AEMO linepack account The linepack account concept Calculations of Linepack account An example of LPA calculations Ancillary payments The ancillary payment concept Calculation of initial ancillary payments Constrained up injection quantity Actual gas injection negative offset Minimum scheduled injection quantity Uplift hedges Examples of calculations of initial ancillary payments Negative initial ancillary payments The AP clawback algorithm The AP flip flop algorithm Uplift payments The uplift payment process AEMO s demand forecast overrides and Market participants effective demand forecasts Calculation of AEMO s adjusted hourly demand forecast overrides Calculations of MPs effective demand forecasts TPO congestion uplift Calculations of market participant s uplift quantity Surprise uplift quantity Congestion uplift quantity Common uplift quantity Uplift payments Allocations of ancillary payments by type of uplift Allocations of uplift payments to market participants 61 Appendix 1: Glossary 63 Appendix 2: References 67 Rules and guides 67 Procedures and Guidelines 67 Other Documents 67 Appendix 3: The gas market system 68 Appendix 4: Determination of Authorised Maximum Interval Quantity (AMIQ) Uplift hedge and authorised maximum interval quantity The uplift hedge process An example of uplift hedge calculation Authorised maximum interval quantity 52

5 SECTION 1 Introduction Victorian businesses and households have relied on natural gas as a major source of energy since it was first rolled out in the state in the late 1960s. Growing needs have led to more sophisticated requirements. In particular, clearer supply and demand signals have been required to enable the energy sector to operate more efficiently, and in March 1999 a wholesale gas market was introduced. This has facilitated gas trading within Victoria. There are now more than 2 million Victorian natural gas customers and annual demand for natural gas (excluding that from gas fired generators) exceeds 200 petajoules (PJ). Annual residential use of natural gas, driven by winter heating and hot water needs, exceeds 90 PJ, by far the highest in the country. In addition, annual demand from gas fired generation has exceeded 30 PJ and is expected to grow considerably, in line with efforts to reduce the carbon emissions from electricity production. The energy sector has continued to evolve, requiring a review of the operation of the market. This detailed study revealed the need for updates to be made and, in February 2007, a new wholesale market commenced operation. This guide explains the workings of the current wholesale gas market providing a technical overview for participants and others interested in gaining a stronger understanding of its operation. In this document: chapter 2 provides an overview of the gas market, gas transportation rights governance through consultative committees and the National Gas Rules; chapter 3 explains the roles of participants in the market and the inter-relationships; chapter 4 explains how gas is traded in the market; chapter 5 provides an overview of the key gas market processes; chapter 6 provides an overview of the gas market systems; chapter 7 explains the concept of authorised maximum daily quantity (AMDQ) and the physical and financial benefits they provide; chapter 8 provides an overview of the gas scheduling process, and the roles and obligations of AEMO and Market Participants (MPs) in relation to this process; chapter 9 provides an overview of the metering process; chapter 10 provides an overview of the gas settlement process; chapters 11 to 16 explain the calculations of the various market payments; and The appendices include the glossary of terms, reference documents, and more detailed process diagrams. This guide is not intended to be a substitute for published procedures and functional specifications. See Appendix 2 for a listing of reference documents. NOTE The contents in this guide are grouped under three different levels of technical complexity. Level 1 Level 2 Level 3 chapters 2 to 6 provide background information to the Victorian declared wholesale gas market. chapters 7 to 10 provide an overview of the key processes in the gas market. chapters 11 to 16 explain wholesale gas market payments using numerical examples. The target audience are gas traders and those interested in more technical details. 2

6 SECTION 2 An overview of the Victorian Wholesale Gas Market This chapter provides a high level overview of the gas market and explains: where it applies; the characteristics of gas injections and withdrawals; how transportation rights are provided; and governance through the market consultative committees and the National Gas Rules. 2.1 Background The wholesale gas market started in March 1999 and was designed to: manage gas supply, demand and linepack of the Victorian Declared Transmission System (DTS) (previously known as the Principle Transmission System (PTS)); allow market participants to easily buy and sell gas; and set a daily gas price (ex post) for all trades. The gas market was reviewed in 2001 then again in 2003/4 through an extensive consultation process with participants operating in the gas market at those times. The 2003/4 review, also known as the Pricing and Balancing Review (PBR), aimed to: provide more efficient and transparent pricing signals; improve market interaction and responses to pricing signals; provide adequate incentives or flexibilities for demand side response; and facilitate investments in pipeline infrastructure. The PBR considered a 3 stage development of the market. It recommended the following changes in the first stage which have been implemented in the current wholesale gas market: gas day start time of 6am AEST (moved forward from 9am in the previous market); ex-ante pricing for each schedule providing pricing certainty (previously daily ex-post daily pricing); five schedules during the gas day at 6am, 10am, 2pm, 6pm, 10pm and ad hoc schedules if required rebidding (of prices and quantities) and updates of demand forecasts for schedules after the first schedule at 6am; deviation payments to be paid by MPs who either under-inject or over-withdraw than their scheduled quantities in each scheduling interval; imbalance payments at the market price to be made to or by MPs for the differences between their scheduled injections and withdrawals; and new methods for calculating Ancillary Payments and Uplift costs for better targeted allocations of market costs to the MPs responsible for causing them. 2.2 The role of AEMO The Australian Energy Market Operator (AEMO) commenced operations on 1 July 2009 and delivers an array of gas and electricity market, operational, development and planning functions. AEMO incorporates the functions previously carried out by six former energy entities, including management of the National Electricity Market (NEM) and the retail and wholesale gas markets of eastern and southern Australia. AEMO also oversees system security of the NEM electricity grid and the Victorian gas transmission network (Declared Transmission System). New responsibilities under AEMO include national transmission planning for gas and electricity and the operation of a Short Term Trading Market for gas (initially in the New South Wales and South Australian hubs). AEMO has the following roles with respect to the Victorian wholesale gas market: operate the DTS and operate and administer the gas market in accordance with the Gas Industry Act and the National Gas Rules (NGR); establish and update system security guidelines for the DTS in accordance to which AEMO is required to operate the DTS in a way to minimise the threats to system security; monitor trading activity in the market; and identify and report significant price variations in the market. LINK Available from the AEMO website at For more details about AEMO s gas market roles and responsibilities see the National Gas Rules on the Australian Energy Market Commission s website: For more details on the system security guidelines see the document System Security Procedures Gas Market Operations > Scheduling Information 3

7 SECTION 2 An overview of the Victorian Wholesale Gas Market 2.3 Victorian gas market coverage The gas market applies to the Declared Transmission System (DTS) shown in Figure 2.1. The DTS comprises of pipelines extending from Longford in the east of Victoria, across to Portland in the south west, central Victoria and north to Albury/Wodonga and Culcairn in New South Wales The Declared Transmission System The Declared Transmission System (DTS) is a relatively complex network of transmission pipelines including the: The DTS is interconnected to the: Eastern Gas Pipeline (EGP) via VicHub (from Longford to Sydney - Horsley Park and Wollongong; The Minerva to Iona pipeline (SEA Gas adjunct); BassGas Pipeline (Lang Lang Gas Plant to Pakenham); Carisbrook to Horsham Pipeline; and The Culcairn to Wagga to Young pipeline (NSW system) The DTS is indirectly connected to the SEA Gas pipeline (Iona to Adelaide pipeline) via the Iona UGS facility. The Tasmanian Gas Pipeline (from Longford to Bell Bay) is connected to the EGP near Longford. Longford to Melbourne pipeline (Longford- Dandenong-Wollert); South West Pipeline (Brooklyn-Geelong-Iona); Brooklyn-Lara Pipeline; Wollert to Albury-Wodonga pipeline; Interconnect to NSW (to Culcairn); and Western Transmission System (WTS) from Iona to Portland (integrated into the DTS in 2003). FIGURE 2.1 MAP OF THE DECLARED TRANSMISSION SYSTEM NEW SOUTH WALES LNG DCG DECLARED TRANSMISSION SYSTEM OTHER TRANSMISSION PIPELINES INJECTION POINT CITY GATE COMPRESSION STATION LIQUIFIED NATURAL GAS STORAGE DANDENONG CITY GATE Australian Pipeline Trust Culcairn VICTORIA Echuca Koonoomoo Albury Wodonga Kyabram Springhurst CS Gas Pipelines Victoria Bendigo NSW Interconnect Carisbrook SEA Gas Pipeline Ballarat Wollert CS Eastern Gas Pipeline Western Brooklyn CS Transmission System Geelong South West Pipeline SEA Gas UGS Iona LNG DCG Gooding CS Bass Gas Lurgi Pipeline Longford Pipeline VicHub Longford Bass Straight Fields Casino, Minerva, Geographe and Thylacine Fields Yolla Tasmanian Gas Pipeline 4

8 SECTION 2 An overview of the Victorian Wholesale Gas Market Injection and Withdrawal points The market has the following gas injection points: Longford located at Longford and connected to the Gippsland gas fields in Bass Strait; VicHub located at Longford, connected to the Gippsland gas fields and supplies gas to and from the EGP; BassGas located at Pakenham supplied by a pipeline from the Lang Lang gas plant; LNG (liquefied natural gas) facility injects gas from the storage/processing plant at Dandenong; Iona injects gas from the Iona gas processing plant at the Iona Underground Gas Storage (UGS) facility; Otway adjacent to the Iona injection pointy - gas sourced from the Otway plant; SEA Gas adjacent to the injection point gas sourced from the Minerva plant; Culcairn on the NSW-Vic interconnect gas injections from the EAPL (NSW) system. VicHub, Iona and Culcairn injection points operate as bi-directional connection points to enable gas to be imported to or exported from the DTS. BassGas, SEA Gas generally act as injection points but can withdraw gas for operational or emergency back-up purposes. There are over 120 withdrawal points in the DTS which allows gas to flow from the DTS to the Victorian distribution networks, some large direct transmission customers, into Iona UGS, or interstate to NSW and South Australia. The inside-cover of this document shows the main pipelines of the DTS and the location of each injection point. Refer to the Victorian Annual Planning Report on the AEMO website for more details. 2.4 Supply and Demand in the gas market Gas transported through the DTS is: supplied to residential, business and industrial customers; used to fuel gas fired power generators (GPG) connected to the DTS (there are currently 5 plants); exported to NSW and South Australia (SA) through the interconnected pipelines; and withdrawn into underground storage UGS at Iona or LNG, if and when required Daily supply-demand At the daily level, gas demand is typically up to 100TJ or so higher on weekdays than on weekends due to reduced loads from the industrial and commercial sectors. Figure 2.2 depicts the daily gas withdrawals (demand) from the DTS during 2007, including the record daily gas withdrawal of 1,280 TJ in July Gas withdrawals over a gas day typically peak in the morning (7-8am) and evening (6-7pm); and are lowest overnight. This peaking is very clear on winter days as shown in Figure 2.2. In contrast, injections are relatively flat over the gas day but are subject to rescheduling. The pressurised gas stored in the pipeline is referred to as linepack. The change in linepack through the gas day is equal to the cumulative difference between injections and withdrawals. As shown in Figure 2.3, linepack is typically high at the beginning of the gas day (ideally close to the daily linepack target ) and is lowest around 10pm in the evening Controllable injections and withdrawals On any given gas day, MPs trade in the gas market based on the imbalances in the gas withdrawn by their respective customer loads and the gas injected into the DTS by each of them. MPs have the ability to control the quantity of gas injections so injections are controllable. However, it is not possible to control the quantity of gas used by the vast majority of end-use customers. There are two categories of withdrawals controllable withdrawals refer to the quantities of gas which MPs bid to withdraw at various prices up to a maximum price bid. In the current gas market, interstate exports and gas withdrawn into the UGS are controllable. uncontrollable withdrawals refer to the quantities of gas which the customers of MPs will withdraw regardless of the market price. This applies to almost all customers in the residential, commercial and industrial sectors and it should be noted that, uncontrollable withdrawals also include demand from gas fired power generators. Annual demand on the DTS is around 220 to 230 PJ depending on gas fired generation levels. Demand is lower in summer and higher in winter due to the increased demand for gas heating. 5

9 SECTION 2 An overview of the Victorian Wholesale Gas Market FIGURE 2.2 DAILY MARKET GAS WITHDRAWALS 1400 GAS POWER GENERATION (GPG) UNCONTROLLABLE (EXCL GPG) CONTROLLABLE TJ /01/07 01/02/07 01/03/07 01/04/07 01/05/07 01/06/07 01/07/07 01/08/07 01/09/07 01/10/07 01/11/07 01/12/07 01/01/08 01/02/08 01/03/08 01/04/08 01/05/08 01/06/08 01/07/08 01/08/08 01/09/08 01/10/08 01/11/08 01/12/08 FIGURE 2.3 INJECTIONS, WITHDRAWALS AND SYSTEM LINEPACK INJECTION/WITHDRAWAL TJ LINEPACK TJ HOURLY WITHDRAWAL HOURLY INJECTION HOURLY LINEPACK 0 0 6:00AM 10:00AM 2:00PM 6:00PM 10:00PM 2:00AM EASTERN STANDARD TIME 6

10 SECTION 2 An overview of the Victorian Wholesale Gas Market 2.5 AMDQ transportation rights The Vic Market has transportation rights which come in the form of authorised MDQ and AMDQ Credits and which are collectively termed AMDQ. These have evolved in the market as follows: AEMO and the transmission pipeline owner have entered into a Service Envelope Agreement (SEA) which determines, amongst other things, transportation capacity of the DTS, including that associated with new pipelines or augmentations, and the obligations of each party in relation to the delivery of the agreed capacity; At the commencement of the market, AEMO allocated the initial DTS transportation capacity to individual large (tariff D) customers in the form of authorised MDQ and the balance collectively to the small customer load (tariff V -residential and small to medium sized commercial/industrial customers); MPs contract for new or additional capacity with APA- GasNet in respect to AMDQ Credits for other pipelines supplying gas (other than for the initial allocation for the Longford to Melbourne pipeline); AEMO allocates AMDQ credit certificates to MPs as directed by the APA-GasNet; MPs who hold authorised MDQ and/or AMDQ credit certificates are entitled to physical (injection and withdrawal) and financial (hedge) benefits. MPs and/or tariff D customers may trade authorised MDQ. 2.6 The National Gas Rules The National Gas Rules govern access to natural gas pipeline services and broader elements of natural gas markets. An amended version of the Rules, taking into account the commencement of AEMO, was passed in the South Australian Parliament and came into effect on 1 July The Rules carry the force of law and are made under the National Gas Law. As applied in Victoria, the Rules set out the processes relating to the operation of the Victorian wholesale and retail gas market, along with the responsibilities and obligations of Market Participants. The purpose of the Rules is to: facilitate an efficient, competitive and reliable gas market; regulate the operation and administration of the gas market; regulate activities of participants in the gas market; and provide for access to the DTS and ensure its security. The Rules cover the following key areas: requirements for participation in the gas market (Part 15A, Division 1); gas scheduling process (Division2, Subdivision 2 ); market participants nominations and bidding processes (Division 2, Subdivision 2); determination of gas market prices (Division 2, Subdivision 3); metering and settlement processes of the gas market (Division 2, Subdivision 6); monitoring market participants prudential requirements (Division 2, Subdivision 7); publication of market and planning information (Division 4) management of emergency, market suspension and system security threats (Division 5); dispute resolution (Division 2, Subdivision 4); and the Rule change process (Division 8). 7

11 SECTION 2 An overview of the Victorian Wholesale Gas Market FIGURE 2.4 THE RULE CHANGE PROCESS Any person (AEMO, Stakeholder, Vic Government etc) Start Propose rule changes Consultative Forum Rule changes considered and submission made to AEMC AEMC Consider proposed rule change, start formal consultation process and consider submissions Notify participants of the rule change Implement the rule change Stop LINK Available from the AEMO website at National Gas Rules 8

12 SECTION 3 Participants in the Gas Market This chapter discusses the different types of participants operating in the gas market, their rights and obligations. Participants can be directly or indirectly involved in the gas market. Those who are entitled to inject gas into, or withdraw gas from, the DTS are also referred to as Market Participants (MPs). 3.1 Participants in the market AEMO AEMO is the national gas and electricity market operator and was established by legislation passed in the South Australian Parliament, which acts as lead legislator for the jurisdictions in which AEMO operates. This legislation enables AEMO to undertake its various market and system operation functions, including management of the wholesale and retail gas market in Victoria and network operation of the DTS. Retailers Retailers purchase gas from gas producers, bid this gas into the market and sell gas to end-use customers. Imbalances are settled through the market. Retailers must be licensed by the Essential Services Commission. As they trade gas in the market they are Market Participants (MPs) Market customers A small number of large customers have elected to participate directly in the wholesale gas market. Market customers are responsible for sourcing their own gas from the gas market, and making commercial arrangements for transportation of the gas through the transmission and distribution networks to their premises. Market customers trade gas and so are MPs Traders Traders are MPs who buy and sell gas from/to other market participants or gas producers. Traders can also trade gas interstate through the interconnecting pipelines. Traders do not have or require a retailer licence. These are also referred in some markets as Shippers. 3.2 Participants indirectly involved in the market The Transmission pipeline owner APA-GasNet is the Transmission pipeline owner (TPO) who owns and maintains the DTS gas transmission system and related facilities used to transport gas from injection points to withdrawal points. Producers A Producer is a participant who processes gas from fields and injects into the DTS. Note: A Producer could become an MP if it bids gas directly into the market. Storage providers A Storage provider is a participant who has a facility that receives and stores natural gas (this gas may have been previously transported through the DTS). The stored gas is injected into the DTS at a later time (e.g. during peak the winter period). Generally the stored gas injected or withdrawn is owned by retailers or traders. Note: A Storage provider could become an MP if it bids gas directly into the market. Interconnected pipeline owners Interconnected pipeline owners own, maintain and operate other transmission pipelines that connect to the DTS. Interconnected pipeline owners interface with the gas market through the connecting flange of their network with the DTS. They enter into connection operating agreements with AEMO. Distributors Distributors (distribution network businesses) own and operate the lower pressure distribution networks. Distributors transport gas withdrawn from a transmission system through their distribution pipelines to the end-use customers. Customers Customers purchase gas from their retailer of choice. Customers are distribution customers if they are connected to a distribution system network. Alternatively, they are transmission customers if they are connected directly to the transmission system. Customers are further assigned by their level of gas demand to tariff classes as follows: tariff D if the consumption at the site is over 10 TJ/year or their maximum quantity is over 10 GJ/hour; or tariff V which applies to residential, small to mediumsized commercial and industrial sites. Figure 3.1 summarises the commercial relationships between the different types of participants in the gas market. 9

13 SECTION 3 Participants in the Gas Market FIGURE 3.1 PARTICIPANTS IN THE GAS MARKET INJECTIONS Producers Storage Providers Interconnecting Pipelines PARTICIPANTS Retailers, Market Customers and Traders MARKET PARTICIPANTS Victorian Declared Wholesale Gas Market (AEMO) MARKET OPERATOR Retailers Market Customers Traders MARKET PARTICIPANTS Interconnecting Pipelines Storage Providers Interconnecting Pipelines Storage Providers PARTICIPANTS Customers WITHDRAWALS TABLE 3.1 REGISTRATION REQUIREMENTS FOR MARKET PARTICIPANTS Requirement Who does it apply to? Who to contact for approval? Prudential All market participants AEMO Connection to AEMO IT systems All market participants AEMO Approved retail licence Retailers The Essential Services Commission Approved gas safety case Retailers Energy Safe Victoria Agreed Transmission Use of System Agreement Agreed Distribution Use of System Agreement All market participants Retailers, market customers APA Distributors 10

14 SECTION 3 Participants in the Gas Market 3.3 Registration To become a participant in the market, interested parties must register with AEMO by providing the required information in the registration kits which are available from AEMO. Interested parties are encouraged to contact AEMO prior to submitting an application so that any areas of uncertainty can be discussed and clarified in advance. In addition to the general requirements listed in the application, there are different requirements which apply to different categories of participants. Table 3.1 lists some specific requirements for MPs and the organisations that MPs need to contact to obtain approvals for those requirements. AEMO will contact the applicant within 5 working days of receiving the application if further information is required. If AEMO does not receive the requested information within a further 15 business days, AEMO may treat the application as withdrawn. If the application is successful, AEMO will advise the applicant of the outcome within 15 working days of receiving the application or within 15 working days on receipt of the requested further information for the application. NOTE Contact [email protected] for further information about how to register as a participant in the Victorian gas market. 3.4 Market consultative forums Changes to market rules and material changes to key procedures occur are initiated through consultative processes involving committees comprised of stakeholders: Gas market consultative forum The AEMO board established a gas market consultative forum of gas industry participants in 1998 to consider and make submissions to it on issues relating to the development or operation of the gas market and any consequential changes to the MSO Rules, and subsequently the National Gas Rules (NGR). This forum is known as the Gas Wholesale Consultative Forum (GWCF). See the AEMO website for more details about the roles and membership of the gas market consultative forum Retail market consultative forum A retail market consultative forum was established in 2002 to provide advice to the AEMO board in its management of these Retail Rules. Changes to the operation of the gas market and the MSO rules, and subsequently the NGR, can potentially have impact on the operation of the Victorian retail market which is governed by the NGR. See the AEMO website for more details about the roles and membership of the retail market consultative forum. 11

15 SECTION 4 Trading gas imbalances MPs, and in particular retailers, generally enter into long-term gas supply contracts with producers and must manage their exposure to the financial risks in the gas market. However, MPs must trade gas amongst each other or buy and sell linepack gas to manage imbalances on each gasday. The diagrams in Figure 4.1 show some possible scenarios of gas traded by MPs. These examples assume there are only two MPs (A and B) involved. Colours are used to indicate the gas bought or sold between each MP (blue and yellow), or trading system linepack imbalances (green). The lower part of each diagram also indicates the source of the purchased gas by colour. FIGURE 4.1 GAS TRADING EXAMPLES A +5GJ INJECTIONS B +10GJ Scenario 1 No gas traded Market Participants A and B withdraw the same quantities of gas as they each inject (5TJ and 10TJ, respectively) during a trading period. Both are in balance and there is no change in linepack. -5GJ -10GJ No gas is traded on the gas market. WITHDRAWALS A +5GJ -4GJ INJECTIONS B +10GJ -11GJ Scenario 2 1 GJ of gas traded, no change in linepack A injects 5 GJ as scheduled and withdraws 4 GJ; B injects 10 and withdraws 11GJ during a trading period. Total injections balance total withdrawals so there is no change in system linepack. In effect A has sold 1GJ to B at the market price which is set by A s marginal price bid for last (5th) GJ it injected WITHDRAWALS A +4GJ -5GJ INJECTIONS B +10GJ -11GJ Scenario 3 More gas withdrawn than injected, reduced linepack A and B both withdraw 1GJ more gas than they each inject resulting in 2 GJ reduction in system linepack. A and B have each bought 1GJ from system linepack gas at the market price to meet the gas demands of each of their customer loads WITHDRAWALS A +7GJ INJECTIONS B +10GJ Scenario 4 One MP over-injected, increased linepack A injects 7 GJ and withdraws 5 GJ. B injects 10 GJ and withdraws 11 GJ. In effect, A sells 1 GJ to B and sells 1 GJ into system linepack at the market price. -5GJ -11GJ WITHDRAWALS 12

16 SECTION 5 Gas market processes There are five main gas market processes including: the allocation of authorised MDQ and AMDQ credit certificates which allocates transportation rights to MPs (see chapter 7 for more details). The authorised MDQ and AMDQ credit certificates are inputs to the gas scheduling, settlements and reporting processes; the gas scheduling process which uses demand forecasts and injection/withdrawal bids to determine the gas market price and the schedules for each MP i.e. the quantities of gas to be injected by each MP at each injection point and the quantities to be withdrawn from the DTS by any controllable loads during the gas day (refer chapter 8); the metering process which includes metering installation, meter registration and metering database maintenance sub-processes (refer chapter 9 ). The metering process provides the required inputs to the settlement process; the settlements process which calculates payments to and from participants (refer chapter 10); and the reporting process which publishes the required market information in the Market Information Bulletin Board (MIBB) (see section 6.6). Figure 5.1 provides an overview of the key processes in the declared wholesale gas market and how they are connected via inputs and outputs. FIGURE 5.1 AN OVERVIEW OF GAS MARKET PROCESSES Inputs Start MP and AEMO inputs Metering Stop Key Processes Allocation of authorised MDQ and AMDQ credit certificates Gas Scheduling Settlements Reporting Outputs Authorised MDQ and AMDQ credit certificates Scheduling inputs and outputs Settlements, quantities and payments The MBB reports 13

17 SECTION 6 The Gas Market System The Gas Market System (GMS) consists of seven inter-related applications. Figure 6.1 shows the links within the GMS. 6.1 Transportation and Market Manager The Transportation and Market Manager (TMM) is the central application software and designed to perform the following functions: storing market information submitted by MPs via the WebExchanger (see section 6.2 for more details about the WebExchanger); storing and maintaining MCE reference and operational data from the SCADA system (see section 6.3 for more details about the SCADA system); organising gas scheduling information required for initiating runs of the Market Clearing Engine (MCE) (see section 6.4 for more details about the MCE); processing the outputs from the MCE; storing and processing demand forecasts provided by MPs before they are forwarded to AEMO Demand Forecasting System (DFS) for further processing (see section 6.7 for more details about the DFS); and organising market data to be published in the Market Information Bulletin Board (MIBB) (see section 6.6 for more details about the MIBB). 6.2 WebExchanger The WebExchanger is a Web based application and provides the interface for MPs to use to submit bid data and other required market information to AEMO. The WebExchanger is an integral part of the MIBB (see section 6.6 for more details about the MIBB). 6.3 SCADA The SCADA system is used to store operational data such as nodal pressures, injection pressures, LNG stock level, heating values and system linepack data. 6.4 Market Clearing Engine The Market Clearing Engine (MCE) is a linear optimisation program (which includes a simplified model of the pipeline system) that produces the operating and pricing schedules for the gas market based upon the schedule input information passed from the TMM. 6.5 Metering and Settlements System The Metering and Settlements system (MMS) has two separate components which operate as follows: FIGURE 6.1 AN OVERVIEW OF THE GAS MARKET SYSTEMS Scada WebExchanger (WEX) Demand Forecast System (DFS) Transportation and Market Manager (TMM) Market Clearing Engine (MCE) Market Information Bulletin Board (MIBB) Metering Management and Settlements (MMS) NOTE See Appendix 3 for more details about the information flow between the applications within the GMS. 14

18 SECTION 6 The Gas Market System The metering system: manages the collection and storage of metered energy values from the metering data agents (MDA) and allocation agents to be used in the settlements process; and processes and stores the adjusted metered energy values to account for gas losses in the DTS. AEMO (or the appropriate MDAs) apply the appropriate Un- Accounted-For-Gas (UAFG) rates at the different system withdrawal points; The settlement system: manages the production and provision of financial settlement statements and supporting data for MPs in the gas market; determines the energy traded by participants using energy values extracted from the metering system and various other inputs from scheduling (for example, market prices) to perform these calculations in relation to each billing period; and performs prudential processing and the calculation of Ancillary and Uplift payments. 6.6 Market Information Bulletin Board The Market Information Bulletin Board (MIBB) is the interface mechanism through which AEMO communicates with MPs. The MIBB: provides transaction interfaces with external MPs; reports market information; and publishes system-wide notices to MPs and the general public. Participants are required to comply with the procedures set out by AEMO which define the communication interfaces and infrastructure for electronic communications between AEMO and participants to support the operation of the gas market. The MIBB reports are made available using Web technologies. Access to these reports will depend on a user s security privileges, which fall into three general classes: public: this type of information is available to everybody, including members of the general public. There is no security control over this information; all participants: this type of information is available to all organisations participating in the gas market; and participant confidential: this type of information is available only to an individual or a restricted group of participants. The generation and publishing of a report can be initiated in three ways: daily at a pre-determined time; triggered by an event; and forced to run by the administrator. A listing of the market reports is published in the document MIBB report participant guide on AEMO s website. The published details can include (but are not limited to) purpose, format, contents, type of access, frequency of reporting and specification of the data fields). LINK Available from the AEMO website at See the document MIBB report participant guide for more details about the published reports Gas Market Data > Data Guides and Manuals 6.7 Demand Forecast System The Demand Forecast System (DFS) prepares forecasts focusing the scheduling process as follows: MP s submit forecast of their loads including individual forecast for very large customers which are collated by the DFS; The DFS also produces AEMO demand forecasts using weather forecasts from the Bureau of Meteorology and input data from the TMM on historical load profiles and levels; and The DFS forwards the demand forecasts and weather data (actual and forecast) to be published in the MIBB. LINK Available from the AEMO website at For more details about the communications procedures see the document Electronic Communications Procedures for Victorian Wholesale Gas Market Gas Market Operations > IT Systems Access 15

19 SECTION 7 Authorised Maximum Daily Quantity Authorised Maximum Daily Quantity (AMDQ) refers to both authorised AMDQ and AMDQ credit certificates. This chapter describes AEMO s process for allocating authorised MDQ and AMDQ credit certificates, outlines the process for obtaining them and explains the benefits they provide to those who hold them. Refer to the National Gas Rules Part 19 Division 4 Subdivision 3 for more details. 7.1 Authorised MDQ Authorised MDQ is a transportation right which provides a hedge against congestion uplift to MPs withdrawing gas from the DTS that has been injected at Longford. Individual tariff D customer sites with authorised MDQ also have in principle preferential treatment in the event of load shedding resulting from a transmission constraint. The initial allocation of authorised MDQ occurred in 1988 when Longford was the only source of gas supply for the DTS, LNG excepted. The total Authorised MDQ was set equal to the peak capacity of the system from Longford of 990 TJ/d. The authorised MDQ was allocated to the following existing and committed new loads (at that time): Contract customer sites - large customer sites typically with demand exceeding 10 TJ per year and now classified as tariff D. The authorised MDQ allocated to each site was set equal to the contract MDQ with any revisions approved by an independent panel; The Interconnect, Wimmera pipeline, Murray Valley towns and DTS compressors; and The balance of the 990TJ was assigned as a block to all residential and small to medium sized commercial and industrials customers - now classified as tariff V customers. Figure 7.1 outlines the process for the initial allocation and re-allocation of authorised MDQ (see page 17). AEMO sub-allocates the tariff V authorised MDQ block amongst the retailers in proportion to their calculated share of the tariff V load on winter high demand days. The proportions are adjusted at the end of each subsequent month for net customer transfers and customer growth during the month*. LINK Available from the AEMO website at See the GMCC paper Apportionment of tariff V Authorised MDQ to Market Participants dated 22 November 2007 for more information Gas Market Operations > Working Groups and Forums > Gas Wholesale Consultative Forum Some customers may change from tariff D to tariff V (or vice versa) subsequent to the initial authorised MDQ allocations. The responsible retailer is required to advise AEMO of this tariff change so that the tariff D and V authorised MDQ can be updated accordingly. If a tariff D site reverts to tariff V, any authorised MDQ allocated to that site is relinquished and will be added to the tariff V block. If a tariff V site converts to tariff D it may be allocated a quantity of authorised MDQ based on its estimated daily loads on winter peak days in 1998 (subject to such data being made available, for example bimonthly billing data may be used as the basis of estimates). Figure 7.1 depicts the process for re-allocation of authorised MDQ. AEMO will conduct auctions of accrued relinquished or identified spare Authorised MDQ from time to time. Refer to Appendix 4 for a detailed diagrammatic representation of AMDQ. * In August 2008, the GMCC has endorsed daily apportionment of tariff V authorised MDQ. The change is expected to be implemented before winter

20 SECTION 7 Authorised Maximum Daily Quantity FIGURE 7.1 ALLOCATION AND RE-ALLOCATION OF AUTHORISED MDQ Transmission pipeline owner Sign off service envelope agreement with AEMO Allocate authorised MDQ Agree with the TPO on modelled capacity Tariff D sites allocation Tariff V block allocation and MP monthly allocation Stop AEMO Determine pipeline capacity (the Common Model) Update metering register Update information Update and publish register of spare capacity Notify retailers and custmers Start Review and update authorised MDQ allocation Retailer Advise AEMO of customer Tariff (D/V) conversion 17

21 SECTION 7 Authorised Maximum Daily Quantity 7.2 Authorised MDQ transfers Currently, transfers of authorised MDQ may be undertaken between: tariff D customer sites; a tariff D customer site and the Reference Hub; the Reference hub and a tariff D customer site; or parties at the Reference Hub In order to ensure that authorised MDQ continues to align with physical capacity, the transfers of auth MDQ take account of location and load diversity: Each tariff D site has had an authorised MDQ diversity factor assigned to it based on 2004 actual gas usage. The diversified AMDQ is equal to the product of the (certificate) authorised MDQ and the diversity factor. In transfers where one or more of the sites is upstream of Pakenham, a location factor is applied to the transferred amount. 7.3 AMDQ Credits The capacity of the DTS has increased as a result of gas system developments and augmentations including the Vic-NSW Interconnect, the South West Pipeline, the connection of the Western Transmission System, the Brooklyn Lara Loop and the BassGas project. Figure 7.2 depicts the process for allocating AMDQ credit certificates which requires that: AEMO and the TPO agree on the increased pipeline capacity resulting from the extension or expansion project and update the SEA accordingly; AEMO allocates the AMDQ credit certificates to MPs as specified quantities for set periods as directed by the TPO. Accordingly, MPs should apply to the TPO for AMDQ credit certificates. Any revenues received by the TPO in exchange for allocating AMDQ credit certificates are deducted from their regulated revenues. MPs with AMDQ credit certificates need to advise AEMO whether the allocated AMDQ credit certificates are to be nominated to sites or the Hub. 7.4 Obtaining AMDQ MPs who wish to acquire authorised MDQ and/or AMDQ credit certificates can: negotiate with holders of authorised MDQ to have an agreed quantity of the allocations transferred to from one site to another or to the hub; negotiate with holders of AMDQ credit certificates to have the agreed quantity transferred at the hub apply and negotiate with the TPO for AMDQ credit certificates if/when they expand the capacity of the DTS or when existing AMDQ Credit contracts others hold expire; contract with the TPO to privately expand the DTS capacity; or bid for and purchase spare authorised MDQ at auctions conducted by AEMO from time to time. 7.5 Benefits of AMDQ By holding authorised MDQ or AMDQ credit certificates MPs will get the benefits of: curtailment rights - in the event of transmission constraints, unauthorised customers will be disconnected from the system ahead of authorised customers; priority in scheduled injections when there are equally priced injections bids those associated with authorised MDQ or AMDQ credit certificates will be scheduled first; reduced Uplift payments as MPs can use part or the whole of their authorised MDQ or AMDQ credit certificates as Uplift hedges (see chapter 15 for more details about Uplift hedges). 7.6 Public Register of Spare Capacity In accordance with the NG Rules, AEMO maintains and publishes a public register of spare capacity on the AEMO website. This register reports capacity of pipelines and the amount, if any, of unallocated authorised MDQ or AMDQ credits. An MP finding itself with excess AMDQ credit certificates may trade some to another party. Transfers of AMDQ credit certificates are currently limited to transfers between parties at the Reference Hub. 18

22 SECTION 7 Authorised Maximum Daily Quantity FIGURE 7.2 ALLOCATION OF AMDQ CREDIT CERTIFICATES MARKET PARTICIPANT Advise AEMO to nominate to hub or sites TRANSMISSION PIPELINE OWNER Start Extend or expand pipelines Consult AEMO MP owns extension expansion? Update or develop service envelope agreement YES Notify MP Direct AEMO to allocate authorised MDQ/AMDQ credit certificates to MP Stop NO AEMO Detirmine pipeline capacity and agree with the TPO Allocate authorised MDQ or AMDQ credit certificates as directed Update metering register Notify MP and (or) customers Update and publish register of spare capacity Allocate authorised MDQ/AMDQ credit certificates and update information See Appendix 4 for a detailed diagrammatic representation of AMDQ credit certificates. LINK Available from the AEMO website at For more details about transfer of authorised MDQ and AMDQ credit certificates see the document AMDQ Transfer Procedure Gas Market Operations > AMDQ The document Wholesale Market (AMDQ Auction) Procedures provides the values of the locational and diversity factors which are specific for each transfer zone Gas Market Operations > Declared Wholesale Gas Market Rules and Procedures 19

23 SECTION 8 Gas scheduling Gas scheduling is the process that AEMO conducts a number of times each gas day to provide injection schedules for each MP and schedules for any controllable withdrawals. The market clearing algorithm used in optimising each operating schedule minimises the cost of supplying the forecast gas demand within the pipeline system security limits. This chapter: provides an overview of the gas scheduling process and the timeline of the schedules; describes the required inputs from MPs and AEMO in conducting this process; and explains the outputs which are reported in the MIBB. LINK Available from the AEMO website at For more details about the gas scheduling process see the document Gas Scheduling Procedures Gas Market Operations > Scheduling Information 8.1 An overview of the gas scheduling process Figure 8.1 depicts the key steps in the gas scheduling process linking MPs and AEMO s data inputs to the scheduling outputs published in the MIBB. There are two different courses of actions depending on whether the state of the operating conditions is normal or abnormal, as discussed below. FIGURE 8.1 THE GAS SCHEDULING PROCESS MARKET PARTICIPANT Start Submit data Stop AEMO SYSTEM OPERATIONS AEMO input data Run the MCE Prepare next schedule NO NO YES Assess results and issue scheduling instructions if results accepted Threat to system security? Intervene? YES Publish in the MBB Monitor gas system Produce ad hoc schedule 20

24 SECTION 8 Gas scheduling 8.2 Normal operating conditions For each schedule and under normal operating conditions, AEMO: collates the required input data from MPs including forecast demand and injection /withdrawal bids, prepares its own input data and demand forecasts and overrides MPs demand forecasts if required (see sections 8.5, 8.6,and 16.2 for more details); runs the Market Clearing Engine (MCE) based on the above input data to produce the optimal schedules; assesses the MCE results; and issues pricing and operating schedules if the MCE results are accepted or re-assesses the input data and repeats the process. 8.3 Abnormal operating conditions Threats to system security Monitoring system security is an integral part of the process which determines whether and when AEMO needs to take actions in case of system security threats which can be caused by: unplanned producer or transmission plant outages; gas demand exceeding transmission system capacity; gas demand exceeding available supply; transmission pipeline gas escapes or damage; or ongoing injections of off-specification gas In the events of system security threats, AEMO will: notify participants of the potential or existing system threats via a system wide notice published in the MIBB; seek participants and MPs advice and corrective actions to mitigate the risks/threats to system security if time is available (for example, AEMO may request MPs to change their market bids and/or bid additional gas); intervene in the market by issuing an ad-hoc operating schedule if time is not available; in the case of persistent off-spec gas, take mitigation steps in accordance with the gas quality guidelines (for example, possible curtailment of off-spec supply and/or scheduling alternative supplies) notify participants and MPs of the return to normal operating conditions if and when the threat to system security is removed; and report the event to the Australian Energy Regulator (AER). AEMO may, if it reasonably considers that the actions available to it under the Gas Industry Act 2001 may not be adequate to alleviate the threat, seek the Victorian Government intervention. AEMO will take appropriate actions including but not limited to: directing the curtailment of customers; injecting gas from AEMO s LNG reserve ; and directing the injection of non-firm gas. LINK Available from the AEMO website at For more details about curtailment of customers see the Gas Load Curtailment and Gas Rationing and Recovery Guidelines Emergency Management > Gas Emergency Management See also chapter 6 Intervention and Market Suspension in the NGR System force majeure events and market suspension A system force majeure event is an event that is likely to materially affect the operation of the market or materially threaten system security and has resulted in a reduction in the normal capacity of part or all of: the transmission system and/or the volume of gas which would otherwise normally flow in the DTS; or a Producer s or Storage Provider s plant or facility. If a system force majeure event occurs AEMO must notify Participants without delay and declare an administered price period Administered price period An administered price period will be invoked if one or more of the following events occur: a system force majeure event is declared; the market has been suspended; a market price or pricing schedule is unable to be published by the required time; or the cumulative price threshold has been exceeded. 21

25 SECTION 8 Gas scheduling AEMO will, as soon as practical, notify all participants via the MIBB of the: occurrence of one or more of the above events; the commencement of an administered price period; and termination of the administered price period when the administered price period is revoked. During an administered price period: the market price must be capped at the administered price cap. The administered price cap is currently set at $40/GJ. This will be reviewed as and when required; and AEMO must determine the market price, pricing schedules and ancillary payments for the scheduling horizon in accordance with the prescribed scheduling procedure for these abnormal events. The administered price period is revoked when: the event that caused the administered price period no longer exists; any distortion of market pricing is unlikely; and no other condition for an administered price period is applicable. A system force majeure event is one of the four cases where AEMO may suspend the market under NGR 347(1) Cumulative price threshold Sustained high prices may trigger an administered price period. The cumulative price is the accumulation of the marginal clearing price (the highest priced bid that is scheduled) over the previous 34 scheduling intervals and the current scheduling interval. The cumulative price threshold is currently set at $3,700. LINK Available from the AEMO website at The Gas Scheduling Procedures provide more details about the procedures to follow under abnormal conditions 8.4 Gas Schedules On any given gas day, AEMO prepares and issues at least nine schedules as depicted in Figure 8.2: five standard schedules for the current gas day at fourhour intervals at 6am,10am, 2pm, 6pm and 10pm (blue); three gas schedules for the next gas day at 8am, 4pm and 12am midnight (purple); one two-days-ahead schedule for gas day after the next day at 12pm mid-day (green); and ad-hoc schedule(s) between standard schedules on the current gas day, but only if there are impending or imminent threats to system security requiring urgent actions; The 6am schedule, also known as the beginning-of-day (BoD) schedule, covers the 24 hours from 6am AEST. Information used and issued in the BoD schedule is updated in subsequent re-schedules. The 10am, 2pm, 6pm and 10pm re-schedules cover the last 20, 16, 12 and 8 hours of the current gas day, respectively. MPs need to submit the required scheduling input data at least one hour prior to the schedule start time for all standard schedules (the exception is the last one-day ahead schedule where the data must be submitted by 10pm). This allows AEMO to compile and assess the input data, run the MCE, and confirm that the outputs are satisfactory before issuing the schedules. Accordingly, the due times for MPs data submissions for the standard schedules are: 5am, 9am, 1pm, 5pm and 9pm for the current gas day; 7am, 3pm and 10pm for the next gas day; and 11am for two-days ahead. Each schedule comprises an unconstrained pricing schedule which sets the market price and operating schedule which take account of constraints. See section 8.5 for details of the required input scheduling data from MPs. Gas Market Operations > Scheduling Information The Administered Pricing Procedure provide more details about the triggering and revocation of administered pricing periods Gas Market Operations > Scheduling Information 22

26 SECTION 8 Gas scheduling FIGURE 8.2 GAS MARKET SCHEDULE TIMELINES Scheduling Inputs due Scheduling Horizon Scheduling Intervals and Horizons gasday Schedule 6 AM 10 AM 2 PM 6 PM 10 PM Issued to 10 AM to 2 PM to 6 PM to 10 PM to 6 AM 5 AM 6 AM to 6 AM current 6 AM 7 AM 6 AM to 6 AM day +1 8 AM 9 AM 10 AM to 6 AM current 10 AM 11 AM 6 AM to 6 AM day PM 1 PM 2 PM to 6 AM current 2 PM 3 PM 6 AM to 6 AM day +1 4 PM 5 PM 6 PM to 6 AM current 6 PM 9 PM 10 PM to 6 AM current 10 PM 10 PM 6 AM to 6 AM day AM *All times are AEST 8.5 Market participant inputs Each MP needs to submit the following input data for each schedule and re-schedule for a given gas day: market bids - injection and controllable withdrawal bids (if applicable); demand forecasts (if applicable); and optionally also submits: injection hedge nominations; and agency injection hedge nominations. The data is submitted via the WebExchanger in the MIBB, available at MPs should obtain accreditation of bid constraints that apply to specific connection points in the DTS where the MPs plan to inject gas to and/or withdraw gas from, in order to reflect facility physical or contractual limitations. See section for more details Market Bids MPs who intend to inject gas or withdraw gas as controllable withdrawals must submit bids via the WebExchanger using the Bid Set input screen*. Figure 8.3 displays the WebExchanger Bid Set data screen for MPs bid data. MPs can specify up to ten steps of prices and daily quantities in each bid for each injection and controllable withdrawal point. For injection bids, the specified bid quantity increases with the increasing bid price, while for controllable withdrawal bids, the bid quantity decreases with the increasing bid price. Bid prices can vary between $0/GJ and the market price cap (VoLL) which is currently set at $800/GJ. MPs may revise price and quantity bids and re-submit them for the re-schedules at least an hour prior to the standard re-schedule times. However, the revised total bid quantities must not be less than that already scheduled in any previous schedules on that gas day. * Market bids can be submitted by AEMO system operators on behalf of a market participant via screens within the TMM. However, this is less common and used only as a back-up procedure if the WebExchanger fails or the MP does not have access to it. 23

27 SECTION 8 Gas scheduling FIGURE 8.3 WEBEXCHANGER BID SET DATA SCREEN AEMO is required to assess and validate MPs submitted data. The assessment process is required to minimise: the risk of conflicting or inconsistent input data from MPs submissions that may undermine the ability of the MCE to determine the optimal schedules for the gas day; and prudential risks to MPs and the market due to using erroneous input data in the scheduling process. The WebExchanger will generate a message to confirm acceptance or rejection of each MP s bids Demand forecasts MPs who supply uncontrollable withdrawals must submit to AEMO hourly demand forecasts for: site specific demand forecasts each tariff D site that has an accredited point specific maximum daily quantity of 5 TJ/day or more, AND a volatile withdrawal pattern (for example, power generators and large refineries), unless exempted by AEMO, and the remaining system-wide uncontrollable withdrawals of their customers. MPs can revise the demand forecasts and submit them to AEMO at least an hour prior to the standard re-schedule times. 24

28 SECTION 8 Gas scheduling FIGURE 8.4 WEBEXCHANGER DEMAND FORECAST INPUT DATA SCREEN Injection hedge nominations An injection hedge nomination is a specified quantity of an MP s scheduled injection from a given injection point which the MP intends to use as an Uplift hedge against the potential financial impact due to system congestion. MPs who intend to do so must: hold sufficient AMDQ associated with that injection point; enter the nominated quantities at each injection point via the Injection hedge nomination data input screen in the WebExchanger; and nominate a % profile for their authorised maximum interval quantity (AMIQ). The AMIQ profile should fit within specified profile limits. If the nominated AMIQ % for a given scheduling interval exceeds the prescribed profile limit it will be rejected. The nominating MP will receive an advice from AEMO about the error and the MP is allowed to correct and re-submit the information. See section 15 for more details about calculations of AMIQ from Authorised MDQ and AMDQ credits and how the AMIQ is used to provide Uplift hedges. 25

29 SECTION 8 Gas scheduling FIGURE 8.5 WEBEXCHANGER INJECTION HEDGE NOMINATION DATA SCREEN Agency injection hedge nomination An MP may allocate a quantity of its scheduled injection to be used as an agency injection hedge nomination for one or more other MPs at a given injection point. To do so, they must provide the required information via the Agency Injection Hedge Nomination input data screen in the WebExchanger. There are two (or more parties) involved in this process: the Injector is the MP who will allocate a quantity of its scheduled injection to another MP as an agency injection hedge nomination (to be used in conjunction with that MP s authorised MDQ or AMDQ credits for the purpose of creating uplift hedges) for a specified period of time; and the Recipient(s) who is the MP receiving the agency injection hedge nomination. The MP providing the agency hedge nomination is required to advise AEMO to allocate injections on either a pro-rata or preference basis in the event that its scheduled injection is less than the amount required to cover both its own injection hedge nomination and any agency injection hedge nomination(s). An MP who receives the agency injection hedge nomination is required to confirm acceptance of the nomination via the WebExchanger. AEMO validates the data submitted by all parties involved and calculates the agency injection hedge as advised above. See section 15 for the application of agency injection hedge in Uplift hedge. 26

30 SECTION 8 Gas scheduling FIGURE 8.6 WEBEXCHANGER AGENCY INJECTION HEDGE NOMINATION SCREEN Accredited bid constraints MPs are required to obtain AEMO s accreditation of bid constraints that they wish to apply to specific injection and withdrawal points in the DTS. These constraints reflect the: flexibility of each individual MP to respond to AEMO s changes to scheduling instructions during the gas day; and physical and contractual limitations at these injection and withdrawal points. The accredited quantities may include: maximum and minimum hourly flow; hourly ramp up/down rates; hourly response time this is the time the given MP requires to respond to a reschedule; bid expiration time this is the time of the day beyond which the given MP will not be able to respond to a reschedule; fixed schedule quantities (schedule restriction); and flexible response. This input data is required to produce the optimal MCE solution for each gas schedule. 27

31 SECTION 8 Gas scheduling 8.6 AEMO s inputs AEMO s key inputs to the scheduling process include: AEMO s demand forecasts and demand forecast overrides (overrides when required); supply and demand point constraints (SDPC) and directional flow point constraints (DFPC); end-of-day linepack target; intra-day adjustments for injection or controllable withdrawals; and other relevant input data Demand forecast overrides Prior to issuing pricing and operating schedules, AEMO: prepares its own hourly forecasts for uncontrollable withdrawals based on weather forecasts from the Bureau of Meteorology; compares its forecasts with the aggregate demand forecasts provided by all MPs; and determines whether to apply an override to the MPs aggregate demand forecasts if its own forecasts are different from those from the MPs by more than the specified amounts. See the document Demand override methodology on AEMO s website for more details. AEMO s hourly demand overrides can be positive or negative depending on whether MPs collectively under or over-forecasts uncontrollable demand by the set levels. See 16.2 for more details about how AEMO applies the override and effectively adjusts MPs demand forecasts Supply and demand point constraints AEMO may apply a supply and demand point constraints (SDPC) to reflect a contractual, physical and/or operating constraint at an injection or withdrawal point that needs to be taken into account during the preparation of a schedule. The SDPCs consist of: injection point constraints which apply to the aggregate schedules on all injectors at a given injection point (for example, based on plant or pipeline capacity limits); and demand point constraints, which apply to the aggregate scheduled withdrawals at a given withdrawal point (for example, an export capacity limitation) The SDPCs are used: by the MCE to reasonably represent the maximum injection or withdrawal capacity at the related injection or withdrawal points, respectively; and to provide a facility to enable AEMO to prescribe an overriding set of constraints on the collective bids at a point. AEMO must set the SDPC parameters according to information supplied by MPs: either from the terms and conditions specified in the operating agreements between AEMO and the associated suppliers/withdrawers of gas; or using information provided directly from MPs (see section 8.5 for more details) End-of-day linepack target System linepack varies over the gas day because of the difference between the relatively constant injection rates but the frequently variable withdrawal rates. A significant proportion of system linepack is required to meet minimum pressure obligations around the system as prescribed in the system security guidelines. System linepack in excess of these requirements is drawn down as an interim source of stored gas supply during times when hourly demand exceeds the aggregate injection rate. Replenishment of system linepack normally occurs overnight when demand is lower than the aggregate injection rate. 28

32 SECTION 8 Gas scheduling It should be noted that too much linepack in a pipeline can increase pressures to the extent that injections into that pipeline can be backed-off causing problems for the operations of some production facilities. AEMO must set an End-of-Day (EoD) linepack target for the system as a whole, and AEMO may set the EoD linepack target for each withdrawal zone if and when required. The current EoD system linepack target is about 340 TJ (MCE linepack). AEMO may change this target from time to time if it considers necessary to do so in order to maintain efficient and safe system operational conditions Intra-day adjustments for injections or controllable withdrawals Gas suppliers typically operate under contracts that commit them to deliver into the DTS a contractual quantity of gas over the gas day. Producers may over-inject later in the day if they under-inject in the first part of the day, so as to meet the contractual daily nominations or amounts. The same applies to the withdrawal side, for example, at interconnected pipelines. AEMO may apply an intra-day quantity difference adjustment (called QDIFF) when producing gas schedules to recognise that the supplier (withdrawer) at a point will make up any shortfall (of schedule versus actual) over the gas day at the time of re-schedule and that there is no need to schedule additional (or less) gas as a result of Deviation from schedule. QDIFF is limited by system security considerations. If the deviations are large and potentially cause system security threats peak shaving gas may be needed to maintain system security Other inputs Other input data include: compressor commitment which specifies details of the committed compressors. This information is required for the MCE to produce the required operating schedules; MCE reference data which are required for the MCE to produce operating schedules. Some of the key reference data include node configuration, withdrawal zones, pipe segments, linepack zones, compressor characteristics; and operational data including nodal pressures. 8.7 Scheduling Outputs AEMO produces and publishes pricing and operating schedules at each scheduling time Pricing schedules The key output in a pricing schedule (PS) is market price. In each PS, the DTS is represented as an infinite tank without physical pipeline or pressure constraints on the quantities of gas flows that can be transported from one point in the system to the next; gas withdrawals (forecast demand plus controllable withdrawals) are met by the cheapest gas bids into the system; and the market price is determined by the marginal price of the cumulative injection bid quantities that are required to meet the aggregate of all MPs demand forecasts and controllable withdrawal bids. The process takes account of each MP s accreditation for the bids, SDPCs, DFPCs and target linepack change for the gas day. 29

33 SECTION 8 Gas scheduling Figure 8.7 illustrates how market price for a given schedule is determined. The example assumes that: beginning of day (BoD) linepack equals EoD linepack at 340TJ; the total scheduled withdrawals are 550 TJ, which includes both uncontrollable and controllable withdrawals; uncontrollable withdrawals are priced at VoLL; the injection bid quantities are stacked up in increasing order of bid price; and the market price is determined at the intersection of the injection and withdrawal bids, which in this example equals $2.72/GJ. A PS is produced for each of the five standard schedules. The market price for an ad-hoc schedule is the same as that in the last standard schedule issued prior to the ad-hoc schedule Operating Schedules The key outputs from the Operating Schedule (OS) are MPs scheduled injections and withdrawals for each MP at each injection/withdrawal point, which are issued to each MP in the scheduling instructions. The OS is generated by the MCE (which includes a simplified physical pipeline model of the DTS where system connection points are grouped into a smaller number of nodes) and takes into account physical pipeline constraints, linepack distribution in the DTS and system limits on pressures and gas flows applicable to each node. When there are constraints in the system it is not possible to schedule the cheapest source of gas to meet all the demand and more expensive gas will need to be scheduled. The scheduled quantities determined in the pricing and operating schedules are therefore not the same. The differences in pricing and operating schedules give rise to Ancillary payments to cover the cost of using more expensive supply. See chapter 14 for more details on Ancillary payments. FIGURE 8.7 DETERMINATION OF MARKET PRICE VOLL End of Day Linepack target 340TJ Uncontrollable Withdrawals (Forecast Demand) Controllable Withdrawal Bids PRICE MARKET CLEARING PRICE $2.72 Injection Bids 340TJ Beginning of Day Linepack Forecast Demand + Controllable Withdrawals = 550TJ QUANTITY 30

34 SECTION 9 The Metering process The metering process includes the following sub-processes: 9.1 Metering installations An MP who intends to: inject gas (or withdraw gas) at a connection point on the DTS; or inject gas at a connection point on a distribution pipeline or withdraw or supply gas for withdrawal at a distribution delivery point (from which a tariff D customer purchases gas from a retailer); must ensure that: there is a metering installation at that connection or distribution delivery point; the metering installation is installed in accordance to the NGR; and the metering installation is registered with AEMO. The person responsible for providing a metering installation is the responsible person and is normally a distributor or the TPO (APA-GasNet). The responsible person must in accordance with the NGR: ensure that its metering installations are provided, installed and maintained; ensure the accuracy of each of its metering installations meet requirements; ensure that each of its metering installations is calibrated in accordance; arrange for remote monitoring facilities as required by AEMO; provide AEMO with the required information for the metering register database; and create, maintain and administer an installation database. The installation database must contain for each metering installation the following details: metering point reference details; the identity and characteristics of metering equipment; and data communication details. 9.2 Metering register AEMO must maintain a metering register of all metering installations which provide metering data used by AEMO for settlement purposes. The metering register may include the following information: meter identification, which is used to identify the meter installation; location in market, which is used to identify the geographical or market groupings each meter installation belongs to; and associated parties which is used to identify the parties the meter installation is associated with including for example the responsible person, the distributor, and MPs etc. 9.3 Metering database AEMO must create, maintain and administer a metering database containing information for each metering installation registered with AEMO. The metering database must include metering data, energy data, energy calculations, gas quality data, substituted data or data provided to AEMO for settlement purposes. 9.4 Conversion to energy The vast majority of gas meters referred to above are used to measure gas volumes which must be converted to energy for wholesale market settlement purposes. A number of strategically located gas chronometers have been installed to measure gas composition and gas heating values, which are used in conjunction with pressures and temperature, to convert metered volumes to energy. Algorithms that calculate the travel time of gas from key injections points (where gas chronometers are located) through the pipeline system enable the heating value of gas to be calculated at withdrawal points on an hourly basis. 31

35 SECTION 10 The Settlements process AEMO conducts the settlement process to determine market fees payable by MPs and facilitate the billing and settlement of transactions between MPs. AEMO must determine for each schedule and each MP: Imbalance and Deviation quantities and payments; Ancillary quantities and payments (if any); Uplift quantities and payments (if any) ; Trading amounts which are the totals of the MP s Imbalance and Deviation payments; and Other applicable market fees (see Part 15A Division 3 of the NGR). MPs are also billed their share of AEMO s daily linepack account balance. Figure 10.1 summarises AEMO s key settlement processes which are explained in more detail in chapters 11 to 15. Numerical examples are provided to explain calculations of these payments. To keep these calculations simple, these examples assume that there are two MPs only. Provisional metering data for a given gas day is available three business days after the end of the gas day. Further validation and substitution of the data is performed over the following 6 to 7 weeks before AEMO issues a final settlement statement to the relevant MPs. MPs are required to pay within 2 business days upon receiving the final settlement statement or a stated date for a revision statement. To assist MPs to prepare for payments of the amount in the final statement, AEMO calculates and issues various estimates of the final settlement amounts to each MP in the interim period. These include: estimates for imbalance, deviation, ancillary and uplift payments 3 business days after the gas day; a preliminary settlement statement 7 business days after the end of the month; and a final settlement statement 18 business days after the end of the month. In addition, AEMO may issue: a revised settlement statement (if required) 118 business days after the end of the month; and an ad hoc revision statement (if required) up to 18 months after the revised settlement. FIGURE 10.1 SETTLEMENT PROCESSES Start AEMO SETTLEMENTS Imbalance payments Deviation payments Calculate Settlements payments VENCorp linepack account Ancillary payments Uplift payments Other applicable market fees and payments Stop 32

36 SECTION 11 Imbalance payments This chapter explains the concept of imbalance payments (IP) and provides numerical examples showing calculations of these payments The imbalance payment Concept In general, MPs endeavour to align their daily gas injections and withdrawals to avoid exposure to the spot market. An MP who injects more gas than it withdraws is selling gas to the gas market whereas an MP who withdraws more gas than it injects is buying gas from the market. MPs must pay the costs for the imbalance quantities in the form of daily imbalance payments (IP) which can be positive or negative. The IP for each MP is calculated based on the imbalance quantities between its 6am scheduled daily injections and withdrawals at the 6am market price plus the subsequent IPs based on changes in the imbalance quantities at each reschedule priced at the reschedule price Calculation of imbalance payments Daily IPs are calculated for each individual schedule of the gas as follows: For the first schedule of the gas day, IP = daily scheduled imbalance quantity * market price ($/GJ) = (daily scheduled withdrawal daily scheduled injection) * current schedule market price For the re-schedules of the gas day, the calculated IP will capture changes in the IP relative to the previous schedule, and IP = change in scheduled imbalance quantity * current schedule market price ($/GJ) If an MP: withdraws and injects the same quantity of gas the IP will be 0; withdraws more gas than it injects the IP will be positive. This implies that the given MP has purchased gas from the gas market and must pay for the overwithdrawal to AEMO; withdraws less gas than it injects the IP will be negative. This implies that the given MP has sold gas to the gas market and is entitled to receive a payment from AEMO for the quantity of gas sold. 33

37 SECTION 11 Imbalance payments 11.3 An example of imbalance payments NOTE The numerical examples presented in the subsequent sections assume that there are 2 MPs in the gas market, 5 schedules for a gas day, 5 scheduling intervals, and 3 bid steps for each schedule. Table 11.1 provides a simple example of the calculations of imbalance quantities and payments for an MP. In this example, the given MP is scheduled to inject 161 GJ and withdraw 142 GJ of gas in the 6am schedule, resulting in a negative imbalance quantity of -19 GJ. Effectively, this MP sells 19 GJ of gas to the gas market and hence is entitled to receive a payment from AEMO. In this case, the IP is -$ based on the market price of $6.50/GJ; at the 10am schedule, the given MP revises its demand forecasts (or possibly controllable withdrawals) and reduces its total scheduled withdrawals by 3 GJ to 139 GJ while the scheduled injections are unchanged. Effectively, this MP sells 22 GJ of gas to the gas market or 3 GJ more than in the 6am schedule. The IP is -$16.80 based on -3 GJ of imbalance quantity and a market price of $5.60/GJ; at the 2pm schedule, the given MP s scheduled injection is reduced by 1 GJ while the scheduled withdrawals remain unchanged compared to the previous schedule. Effectively, the MP buys back 1 GJ of gas that it was scheduled to inject at the 10am schedule and pays an IP of $4.50 for it at the market price of $4.50/GJ. It should be noted that the MP makes a profit of $1.10 for the 1 GJ of gas sold at $5.60/GJ at 10am but bought back at $4.50/GJ at the 2pm schedule; since there are no revisions to the scheduled injections and withdrawals in the subsequent re-schedules no further IPs are incurred; and the MP pays a total daily IP of -$135.8 being the sum of the IPs across all 5 schedules. TABLE 11.1 CALCULATIONS OF IMBALANCE PAYMENTS Schedule Scheduled injection A Scheduled withdrawal B Market price ($/GJ) C Imbalance D = B - A Change in Imbalance E Imbalance payment ($) F = D (or E) * C Who pays 6AM $ NA -$123.5 AEMO 10AM $ $16.8 AEMO 2PM $ $4.5 MP 6PM $ $0.0 NA 10PM $ $0.0 NA 34

38 SECTION 12 Deviation payments This chapter explains the concept of deviation payments (DP) and provides examples showing calculations of these payments The deviation payment concept DPs are costs used to settle differences between MPs scheduled and actual behaviour. MPs deviations from their demand forecasts and scheduled quantities (injections and withdrawals) in a given schedule will have physical and financial impacts on the outcomes of the next schedule. For example, if an MP under-forecasts their demand (or under-schedules injections) in the 6am schedule this will cause a decrease in linepack requiring more gas to be injected at the 10am schedule, and potentially an increase in gas market price. Likewise, deviations in the 10am scheduled quantities and demand forecasts will affect the 2pm market outcomes. DPs also provide MPs with a tool to trade linepack between schedules by managing their net positions in supply and demand Calculations of deviation payments DPs for a given schedule are calculated from the net deviation quantities in energy multiplied by the market price of the next schedule. Deviation quantities and payments can be positive or negative. Positive (negative) payments mean that MPs will pay (be paid) for the net deviation quantities. The DP is calculated for the relevant scheduling interval (SI) in each schedule according the following formula: DP = (current SI withdrawal deviation current SI injection deviation) * next schedule market price = ((current SI actual withdrawals current SI scheduled withdrawals) (current SI actual injections current SI scheduled injections)) * next schedule market price 12.3 An example of deviation payments In the example shown in Table 12.1, the given MP receives DPs at the 6am and 6pm schedules as the MP s actions result in increases in net supplies in the system in these schedules. However, the given MP must pay for the negative deviations for the 10am, 2pm and 10pm schedules. TABLE CALCULATIONS OF DEVIATION PAYMENTS Schedule Scheduling interval Sched injection A Actual injection B Injection Deviation C = B - A Sched withdrawal D Actual withdrawal E Withdrawal Deviation F = E - D Net Deviation G = F - C Next Schedule Market price ($/GJ) H Net Deviation payment ($) I = G * H Who pays 6AM 6AM - 10AM 10AM 10AM - 2PM 2PM 2PM - 6PM 6PM 6PM - 10PM 10PM 10PM - 6AM Total daily $5.6 -$33.6 AEMO $4.5 $18.0 MP $3.1 $9.3 MP $2.5 -$2.5 AEMO $3.1 $49.6 MP $40.8 MP 35

39 SECTION 13 AEMO linepack account This chapter explains the concept of AEMO linepack account and provides examples of calculations of these payments The linepack account concept The AEMO linepack account (LPA) is a market settlement account that conceptually purchases gas from the gas market to supply AEMO s demand forecast overrides and trades linepack between schedules and gas days. The LPA also accumulates the costs associated with unaccountedfor-gas (UAFG). When AEMO performs a demand forecast override for a schedule, the demand override acts to change system linepack because purchasing (or selling) gas for a demand forecast override is equivalent to purchasing (or selling) the notional change in linepack. The price applicable to the gas purchase/sale is the market price for the given schedule. The next time AEMO schedules gas, that schedule will treat the change in linepack as a change in supply (from linepack) available to cover withdrawals in that schedule. In effect, the linepack account is selling the notional change in linepack at the market price of the next schedule. The LPA is not associated with any individual MP, but effectively accounts for any non-zero net settlement credits or debits from deviations and imbalances in each schedule. The LPA may build up a surplus or deficit of funds which will be cleared on a daily basis by apportionment to each MP based on their total actual withdrawals for the day Calculations of Linepack account The LPA for each schedule is the sum of all MPs imbalance and deviation payments for that schedule. The LPA accumulates over the day with the end-of-day balance apportioned to each MP according to their share of actual withdrawals for that day. The cumulative linepack account can be positive (resulting in a surplus to be paid to all MPs) or negative (resulting in a deficit to be funded by all MPs) An example of LPA calculations Table 13.1 shows the LPA calculations for each schedule of a gas day. The IPs and DPs for MP B are shown previously in Table For the given gas day, the net LPA payment is -$3.50 being the sum of -$48.30 of IP and $44.80 of DP. TABLE 13.1 CALCULATION OF LINEPACK ACCOUNT Scheduling Interval Market participant A Market participant B Total Imbalance payment A Deviation payment B Imbalance payment C Deviation payment D Imbalance payment E = A + C Deviation payment F = B + D Linepack Account payment G = E + F 6AM - 10AM $58.5 $11.2 -$ $33.6 -$65.0 -$22.4 -$ AM - 2PM $0.0 -$9.0 -$16.8 $18.0 -$16.8 $9.0 -$7.8 2PM - 6PM $13.5 -$6.2 $4.5 $9.3 $18.0 $3.1 $21.1 6PM - 10PM $15.5 -$7.5 $0.0 -$2.5 $15.5 -$10.0 $5.5 10PM - 6AM $0.0 $15.5 $0.0 $49.6 $0.0 $65.1 $65.1 Total daily $87.5 $4.0 -$135.8 $40.8 -$48.3 $44.8 -$3.50 In this example, MP A and B must fund 46% and 54% of the LPA which are calculated based on their share of the total daily withdrawals as shown in Table TABLE 13.2 ALLOCATIONS OF DAILY LINEPACK ACCOUNT TO MARKET PARTICIPANTS Market participant Actual daily withdrawal Proportion of actual daily withdrawal Daily linepack payment ($) A % -$1.62 B % -$1.88 Daily total % -$

40 SECTION 14 Ancillary payments This chapter explains the concept of ancillary payments (AP) and provides examples showing calculations of these payments The ancillary payment concept As discussed in chapter 8, it is not always possible to schedule the cheapest gas supplies to meet the required demand for a given gas day. This normally happens when the system is congested resulting in gas that is more expensive than the market price being scheduled. Ancillary payments are compensatory payments to MPs who are affected by these events. In other cases (albeit less likely), MPs may be scheduled to withdraw gas that is more expensive than their bid prices. This section will focus on injection AP. The method for calculating withdrawal AP is similar to that presented below with some minor differences. See the references below for more details about calculations of withdrawal AP and AP in general. LINK Available from the AEMO website at For more information on Ancillary Payments see the following documents Victorian Gas Market Stage 1 Design Functional Description (section 5) Ancillary Payment Procedure Ancillary Payment Functional Design V8.1 Gas Market Operations > Metering and Settlements The original AP procedure, implemented in February 2007, was enhanced in May 2008 following the experience in winter The enhancements are designed to improve market efficiency with the additions of the AP clawback and AP flip flop algorithms. Figure 14.1 displays the steps involved in the AP calculations which include: calculation of initial APs (see section 14.2); adjusting the initial APs for AP clawback (see section 14.3); and applying the AP flip flop algorithm to APs which have been adjusted for clawback (see section 14.4) Calculation of initial ancillary payments APs are calculated for each MP s bid step at each injection point and for each schedule of the gas day. For the BoD (6am) schedule, the initial AP for each MP s bid step at each injection point and each schedule equals: Initial AP = constrained up injection quantity * max (0, 6am bid price 6am market price) See section for more details about constrained up injection quantity. For each re-schedule, the AP for each bid step is calculated based on the change in constrained up injection quantity which can increase or decrease to reflect the extent of system congestion in the re-schedules. For each re-schedule, the AP for each bid step at a given injection point is equal to: Initial AP = change in constrained up injection quantity * max (0, current bid price current market price) The above formulae imply that initial APs for the first schedule of the gas day, if any occur, are always positive but may be positive or negative for the re-schedules. If the constrained up injection quantity decreases in the re-schedules, the change in constrained up injection quantity in the re-schedules will be negative and so will be the initial APs (see section for more details about negative APs). 37

41 SECTION 14 Ancillary payments FIGURE 14.1 ANCILLARY PAYMENTS CALCULATIONS Calculate Settlements payments Start Calculate AGINO Calculate MSIQ Calculate applicable price Calculate Uplift hedge Pricing and operating schedules Calculate constrained up quantity AEMO SETTLEMENTS Initial AP =$0 YES Uplift hedge applies? NO Calculate initial AP Adjust initial AP for clawback Apply AP flip flop Stop 38

42 SECTION 14 Ancillary payments Constrained up injection quantity The constrained up injection quantity (CUIQ) is the quantity of gas that is eligible for an AP (shown as the blue shaded area in Figure 14.2 below). The CUIQ is equal to the operating schedule (OS) quantity minus: the scheduled quantity of gas that is not injected (actual gas injection negative offset or AGINO, shaded in yellow); and the minimum scheduled injection quantity (or MSIQ, shaded in green) which represents market participants self-imposed injection constraints Actual gas injection negative offset If an MP injects less gas than scheduled in the OS it will not receive an AP for the under-injected quantity of gas. This amount is termed actual gas injection negative offset (AGINO) and is always positive. Calculations of AGINO for the final OS AGINO for each bid step in the last approved OS is calculated as follows: AGINO = maximum (0, OS injection - actual injection) Constrained up injection quantity (CUIQ) = OS quantity AGINO MSIQ In addition, any quantity of the CUIQ used for uplift hedge purposes will not receive an AP (see section 15 for more details). See section for more examples of calculations of AP. FIGURE 14.2 CALCULATION OF CONSTRAINED UP INJECTION QUANTITY Bid price for constrained on gas = $5 Operating Schedule Quantity = 20 GJ PRICE Market price = $3 Injection bids Gas scheduled but not injected (AGINO) = 5 GJ Constrained up injection quantity (CUIQ) = = 10 GJ Minimum scheduled injection quantity (MSIQ) = 5 GJ 39

43 SECTION 14 Ancillary payments The following examples illustrate calculations of AGINO assuming there are three bid steps in the final schedule. The example in Table 14.1 shows that an MP is scheduled to inject a total of 30 GJ of gas in the OS but only injects 25 GJ. Consequently, the AGINO of 5 GJ in bid step 3 is not entitled to AP. TABLE 14.1 CALCULATIONS OF AGINO BY BID STEPS (SCHEDULED GREATER THAN ACTUAL) Bid step Final OS injection A Actual injection B AGINO C = max (0, A B) Total The example in Table 14.2 illustrates the case where the given MP injects 35 GJ, or 5 GJ more than the OS, the over-injection of 5GJ is also not entitled to any AP, however it is not included in the AGINO calculation. Calculations of AGINO for schedules prior to the final OS It might be conceived that the above formulas can be used to calculate the AGINOs for schedules prior to the last OS. However, to do so may potentially reduce the OS quantity of gas that an MP has that is eligible for AP. For example, an MP s scheduled injection may be high in the early schedules of a gas day (because of high demand forecasts) but decreases in the later schedules (when demand forecasts are reduced). The AGINOs for the earlier schedules according to the above AGINO formulas - would be higher than they should be. The example in Table 14.3 shows that an MP is scheduled to inject 10 GJ at the 6amOS. The OS scheduled quantity is subsequently reduced to 5 GJ, 7 GJ and 8 GJ before increasing to 10 GJ at the final schedule. If the formula for calculating AGINO for the final schedule was used to calculate the AGINOs for the prior schedules, the AGINO would be 5 GJ, 0 GJ, 2 GJ, 3 GJ and 5 GJ for schedules 1 to 5 respectively. The quantity of gas eligible for AP is therefore 5 GJ for all schedules including the 6am schedule. This implies that the MP fails to deliver 5 GJ of gas at the 6am schedule, but this is not correct because the MP is subsequently required to reduce its injections from 10 GJ to 5 GJ in the 10am schedule. TABLE 14.2 CALCULATIONS OF AGINO BY BID STEPS (SCHEDULED LESS THAN ACTUAL) Bid step Final OS injection A Actual injection B AGINO C = max (0, A B) Total TABLE 14.3 AN EXAMPLE OF CALCULATIONS OF AGINO ASSUMING THE AGINO FORMULA FOR THE FINAL OPERATING SCHEDULE IS APPLIED TO THE PRIOR SCHEDULES Schedule 6AM 10AM 2PM 6PM 10PM Actual OS GJ AGINO GJ Gas eligible for AP (assuming no MSIQ)

44 SECTION 14 Ancillary payments The algorithm used to calculate AGINO for schedules prior to the final OS: calculates changes in AGINO from the final schedule; and takes into account the changes between the OS quantity in the final OS and the least quantity of gas scheduled at the current and all the subsequent OS. For each schedule prior to the final OS, the calculations involve the following steps: Step 1: calculate the least scheduled quantity of all schedules from the current schedule to the final schedule. Step 2: calculate the difference between the OS quantity in the final schedule and the above least scheduled quantity. Step 3: calculate AGINO as the difference between the final schedule AGINO and the quantity calculated in step 2 above. The example in Table 14.4 illustrates the current method for calculating AGINO for schedules prior to the final schedules and shows that for the 6am schedule, the MP is scheduled to inject 10 GJ of gas; the least scheduled quantity of gas is 5 GJ which is the minimum scheduled quantity across all schedules 1 to 5; the difference between the scheduled quantity in the final OS and the least scheduled quantity is 5 GJ (=10 GJ 5 GJ); the AGINO is therefore 0 GJ. This means that all the OS quantity of 10 GJ in the 6am schedule is eligible for AP (compared with 5 GJ in Table 14.3 which is calculated using the AGINO method applicable for the final OS) Minimum scheduled injection quantity The minimum schedule injection quantity (MSIQ) is the daily quantity of gas that is injected as a result of MPs imposed constraints such as ramping limits and minimum flow constraints in the pricing schedules (for example, minimum hourly or daily quantities, see details in section 8.5). Because these quantities of gas flow regardless of market price they are hence not eligible for APs. The MSIQ is calculated for each bid step in each schedule starting from the final schedule as follows: the MSIQ for each bid step in the final schedule is equal to the PS (pricing schedule) quantity for that bid step; and the MSIQ for each bid step in the schedules prior to the final schedule is equal to: the PS quantity if the bid price for that bid step is higher than the associated market price. The rationale is that any scheduled gas in the PS which costs more than the market price would have only flowed because of the MP s imposed constraints; and the lesser of the PS quantity for that bid step in that schedule and the MSIQ for that bid step in the following schedule if the bid price is less than the market price. TABLE 14.4 CALCULATIONS OF AGINO ACROSS SCHEDULES Schedule 6AM 10AM 2PM 6PM 10PM Actual OS GJ (1) Least scheduled quantity GJ (current and subsequent schedules) (1) (2) Final OS quantity less least schedule quantity (2) (3) AGINO GJ (final schedule AGINO (2)) (4) Gas eligible for AP (after subtracting AGINO)

45 SECTION 14 Ancillary payments An example of calculations of MSIQ The example in Table 14.5 illustrates the calculations of MSIQ starting from the final schedule. The MSIQ for the final schedule equals the PS quantity of 5 GJ. For the 6pm schedule, the bid price is less than the market price and therefore the MSIQ is 5 GJ being the lesser of the PS quantity (15 GJ) and the MSIQ in schedule 5 (5 GJ). For the 6am to 2pm schedules, bid prices are higher than market prices. Gas can only be scheduled because the MP has requested gas to be injected to satisfy their constraints. The MSIQ are therefore equal to the PS quantities. TABLE 14.5 CALCULATIONS OF MSIQ ACROSS SCHEDULES Bid price ($/GJ) Market price ($/GJ) Schedule 6AM 10AM 2PM 6PM 10PM $3.0 $3.0 $4.0 $4.0 $4.0 $2.0 $2.0 $1.0 $5.0 $1.0 PS GJ MSIQ Uplift hedges Any quantity of gas in the OS which is used as an uplift hedge will not be eligible for AP. See section 15 for more details about uplift hedges Examples of calculations of initial ancillary payments The example in Table 14.6 shows calculations of the initial AP for the BoD schedule based on: constrained up quantity (column D); the applicable price (column G); and Uplift hedge information (column I). In this example, the total OS quantity is assumed to be 30 GJ. Bid step 1 is used as an uplift hedge and hence is not eligible for an AP. The AP for bid step 2 is $20 based on 10 GJ of CUIQ and the applicable price $2.0/GJ. The AP for bid step 3 is $20.0 base on the constrained up quantity of 5 GJ at $4.0/GJ of CUIQ Negative initial ancillary payments The initial APs for the first schedule of the gas day, if any occur, are always positive but may be positive or negative for the re-schedules. Negative initial APs occur if the scheduled quantities in the re-schedules decrease causing a negative change in the calculated CUIQ. In general, negative APs most likely occur under one of the situations discussed below. Negative AP following positive APs AP flip flop The example in Table 14.7 illustrates the situation where a negative AP occurs following a positive AP in the previous schedule. It is assumed that there are only 2 schedules. TABLE 14.6 CALCULATIONS OF ANCILLARY PAYMENTS Bid step Final OS injection A MSIQ B AGINO C CUIQ D = max (0, A-B-C) Bid price ($/GJ) E Market price ($/GJ) F Price ($/GJ) G = max (0,E-F) AP ($) H = G x D Uplift hedge flag I AP ($) J = 0 if I = Y $3.00 $3.10 $0.00 $0.00 Y $ $5.10 $3.10 $2.00 $30.00 N $ $7.10 $3.10 $4.00 $20.00 N $

46 SECTION 14 Ancillary payments In the first schedule, an MP: is scheduled to inject 10 GJ of gas at the bid price of $5.0/GJ while the market price is $3.5/GJ; has sold 10 GJ of gas to the market and receives an IP of $35 (= 10 * $3.5); receives an AP of $15 (=10 * ($5 $3.5)) as a compensation payment for gas injected which costs more than the market price; and receives a net payment of $50 being the sum of total IP and AP. In schedule 2, the MP: is scheduled to inject 0 GJ and the market price has fallen to $3.0/GJ; has to buy back 10 GJ of gas from the market (which it sold to the market in the first schedule) and pays an IP of -$30 = (-10 * $3); refunds an AP of -$20 = (-10 * ( $5 -$3)) as the constrained up gas is no longer required; and has to pay back $50 of IP and AP for the quantity of gas which it has to buy back from the market. In this example, the total IPs are $5 while the total APs are -$5. The MP is therefore even when IPs and APs are considered in conjunction. However, if the market price fell below $3.0/GJ (for example $2.50/GJ) the AP refund would be -$25 giving rise to a total AP of -$10. Under this scenario, the MP would be out of pocket by -$5 when IP and AP are considered together. TABLE 14.7 AN EXAMPLE OF NEGATIVE AP FOLLOWING A POSITIVE AP IN THE PREVIOUS SCHEDULE Schedule 1 2 Total Bid price $5.0 $5.0 Market price $3.5 $3.0 OS GJ Change in CUIQ GJ IP $35.0 -$30.0 $5.0 AP $15.0 -$20.0 -$5.0 Total IP & AP $50.0 -$50.0 $0.0 It should be noted that the initial AP changes sign from positive (in the first schedule) and negative (in the second schedule). This is referred to as AP flip flop. The AP flip flop algorithm was implemented in May 2008 to address the issue of large APs changing sign from one schedule to the next. See section 14.4 for more details. Negative AP due to market participant s re-bidding AP clawback The example in Table 14.8 illustrates the situation where a negative AP occurs because the given MP re-bids its gas higher in the re-schedule. Compared to the example in Table 14.7, the only change in this example is the increased bid price in the re-schedule. The market outcomes and payments for the first schedule are the same as for the example in Table In schedule 2, the MP: rebids its gas higher at $10/GJ and gas which was scheduled in schedule 1 is no longer required; has to buy back 10 GJ of gas from the market (which it sold to the market in the first schedule) and pays an IP of -$30 = (-10 * $3); refunds an AP of -$70 = (-10 * ( $10 - $3)) as the constrained up gas is no longer required. The refund is much larger than the initial AP the MP receives in the first schedule; and has to pay back $100 of combined IP and AP for the quantity of gas which it has to buy back from the market. In this example, the total IPs are $5 but the total APs are -$55. The total net payment is a loss of -$50 when IPs and APs are considered in conjunction. This implies that, by re-bidding gas at a higher price in the re-schedules, an AP may incur a negative AP which can be much larger than the positive AP it receives in the earlier schedule(s). The AP clawback algorithm was implemented in May 2008 to address the over-recovery of AP when an MP incurs large negative APs by re-bidding gas injections at a higher price in re-schedules in an attempt to be de-scheduled or scheduled down. See section 14.3 for more details. 43

47 SECTION 14 Ancillary payments TABLE 14.8 AN EXAMPLE OF NEGATIVE AP DUE TO MARKET PARTICIPANT S RE-BIDDING Schedule 1 2 Total Bid price $5.0 $10.0 Market price $3.5 $3.0 OS GJ 10 0 Change in CUIQ GJ IP $35.0 -$30.0 $5.0 AP $15.0 -$70.0 -$55.0 Total IP & AP $50.0 -$ $50.0 In schedule 2, the MP: is scheduled to inject 0 GJ and market price has fallen to $3.0/GJ; has to buy back 10 GJ of gas from the market (which it sold to the market in the first schedule) and pays an IP of -$30 = (-10 * $3); refunds an AP of -$5 = (-10 * ( $3.5 -$3)) as the constrained up gas is no longer required; and has to pay back $35 of IP and AP for the quantity of gas which it has to buy back from the market. In this example, the total IPs are $5 and the total APs are -$5. The total net payment is $0 when IP and AP are considered in conjunction, and the MP is even. The net payment can be positive or negative (ie the MP can make a profit or a loss) depending on the difference between the applicable market and bid prices. Negative AP with no preceding positive APs This situation occurs frequently on gas days when the system is not constrained and most likely in non-winter months. In general, this happens when the scheduled quantity in the OS decreases in the re-schedules, and at the same time market price falls below the MP s bid price. In the first schedule shown in Table 14.9, the MP: is scheduled to inject 10 GJ of gas at the bid price of $3.50/GJ while the market price is also $3.50/GJ; has therefore sold 10 GJ of gas to the market and receives an IP of $35 (= 10 * $3.5); receives an AP of $0 (=10 * ($3.5 $3.5)); and receives a total IP and AP of $35. TABLE 14.9 NEGATIVE AP WITH NO PRECEDING POSITIVE AP Schedule 1 2 Total Bid price $3.5 $3.5 Market price $3.5 $3.0 OS GJ 10 0 Change in CUIQ GJ IP $35.0 -$30.0 $5.0 AP $0.0 -$5.0 -$5.0 Total IP & AP $35.0 -$35.0 $0.0 LINK Available from the AEMO website at The GMCC (now GWCF) paper GMCC (meeting 124) explains the causes of negative AP Gas Market Operations > Working Groups and Forums > Gas Wholesale Consultative Forum 44

48 SECTION 14 Ancillary payments 14.3 The AP clawback algorithm When a market participant is scheduled to inject an amount of gas for the day, and this amount is reduced in a subsequent re-schedule, the positive APs in the earlier schedules are clawed back i.e. recovered negative ancillary payments. In the case where there is no change in the relevant MP s bids and no change in the market prices, and if the quantity of gas scheduled in previous OS is completely scheduled off, the negative APs will match and cancel out the earlier positive APs. However, if an MP increases its bid prices in subsequent schedules (while the relevant market prices do not change) and is consequently scheduled off or down, the MP could incur a negative AP which could be much greater than the positive AP it received in the earlier schedules. This is because the price for each GJ associated with the negative AP (being the difference between the MP s increased bid prices and market prices at the subsequent schedules) is greater than that in the previous schedules when positive APs were initially incurred. Negative APs could therefore result in a substantial cost over-recovery by the market. Accordingly, in these cases when calculating a negative AP, account must be taken of the relevant bid price(s) in the earlier schedule(s) that lead to the positive APs when the block(s) of gas in question are first scheduled on. The AP clawback algorithm was implemented in May 2008 following the experience in winter 2007 which shows that some MPs received large negative APs because they re-bid their gas injections at a higher price in subsequent schedules. A three-step approach is applied to adjust the initial AP which is calculated according to the formula in section The adjustments apply to each bid step in each schedule and for each injection (and also withdrawal) point. Step 1: Matching schedules to determine bid prices to use Step 1 matches schedules where a facility is constrained on (at bid price 1) with subsequent schedules where the constrained on quantity is reduced (at bid price 2). Step 2: Calculate the revised AP for schedules with a negative initial AP The AP for schedules with negative AP is re-calculated, by using the lesser (or the greater for a withdrawal) of bid price 1 and bid price 2 as the bid price used in calculating the revised AP. This step eliminates the excessive clawback of APs due to MP s re-bidding, but maintains negative APs stemming from other causes. No changes are made to positive APs. Step 3: Adjust the revised AP by re-instating some of the negative AP removed in step 1 The adjustments in step 2 may have removed too much negative AP from the relevant bid steps in the affected schedules, to the extent that the total revised (positive) AP for these schedules increases compared to the initial AP before the adjustments. This means that MPs whose actions cause the initial positive APs need to pay more uplift charges. Step 3 of the approach involves applying a correction to the revised APs for each bid step which have been adjusted in step 2. The following rules apply: If the total revised AP for the schedule is negative then no further changes are made. If the total revised AP for the schedule is positive and equals the total initial AP then no further changes are made. If the total revised AP for the schedule is positive and does not equal the total initial AP, and the initial AP for the bid step is negative, then the AP clawback will be re-instated to the bid step either partially or in full. The correction to the bid step AP is based on the change in CUIQ multiplied by an average rate of re-instated AP. The latter is calculated by dividing the total revised AP for the schedule by the greater of the total changes in positive and negative CUIQ for that schedule. 45

49 SECTION 14 Ancillary payments Figure 14.3 illustrates how negative changes in CUIQ are systematically matched with positive change in CUIQ so that the lowest bid price for paired schedules can be identified and is then used to calculate the revised AP for the relevant bid steps. In calculating the revised AP for schedule 3, the minimum bid prices in the paired schedules (1,3) and (1,2) are used while the minimum bid prices in the paired schedules (4,5) and (1,5) are used to calculate the revised AP for schedule 5. In the top diagram in Figure 14.3, each block represents the change in CUIQ. Schedules 3 and 5 have negative changes in CUIQ. The matching is as follows: -7 GJ in schedule 3 are matched with +5 GJ and +2 GJ in schedule 2 and 1 respectively; and -16 GJ in schedule 5 are matched with +12 GJ in schedule 4 and +4 GJ in schedule 1. FIGURE MATCHING BIDS FOR CLAWBACK PRICING SCHEDULED QUANTITY +10 GJ +5 GJ -7 GJ +12 GJ -16 GJ Each block represents the change in CUIQ SCHEDULE SCHEDULED QUANTITY S2 Bid Price - S1 Bid Price + - S4 Bid Price - S1 Bid Price Each negative block is paired with the block where the gas was originally scheduled SCHEDULE LINK Available from the AEMO website at The GMCC paper GMCC (meeting 124) explains the causes of negative AP, and the GMCC paper GMCC (meeting 136) explains how negative AP is addressed Gas Market Operations > Working Groups and Forums > Gas Wholesale Consultative Forum 46

50 SECTION 14 Ancillary payments An example of AP clawback Table illustrates the AP clawback mechanism. This example assumes that the actual quantity of gas flowed meets the final OS injection so that the AGINO is zero for all schedules. No gas from this injection point is scheduled in the PS and the MSIQ is hence 0 for all schedules. The CUIQ is therefore equal to the OS quantity. The CUIQ for the 6am schedule is 10 GJ. In the 10am schedule, the MP increases its bid price for the same 10 GJ of gas and consequently is scheduled down to 5 GJ and there is no change in the market price. In the 2pm schedule, the MP increases its bid price again and is scheduled down to 3 GJ (which is the gas already scheduled to flow in the first two scheduling intervals). The MP increases its bid prices again in the 6pm and 10pm schedules with no further gas injections scheduled for the remaining scheduling horizon such that the OS quantity remains at 3 GJ in the last 2 schedules. The revised APs are -$10 and -$6 for the 10am and 2pm schedules respectively as shown in the calculations in the box below. 10am schedule ancillary payment clawback = change in constrained quantity * Maximum ($0, Minimum (pairs of bid prices 1 & 2) market price) = -5 * Maximum ($0, Minimum ($10, $20) - $8) = -5 * Maximum ($0, $2) = -$10 2pm schedule ancillary payment clawback = change in constrained quantity * Maximum ($0, Minimum (pairs of bid prices 1 & 3) market price) = -2* Maximum ($0, Minimum ($10, $30) - $7) = -2 * Maximum ($0, $3) = -$6 The change in CUIQ is 10 GJ for the 6am schedule, and -5 GJ and -2 GJ for the 10am and 2pm schedules respectively. The negative changes in CUIQ s in the latter schedules are paired with the CUIQ in the 6am schedule for the purpose of identifying the minimum bid prices of the pair to use to calculate the revised AP. The two pairs of schedules are (6am,10am) and (6am, 2pm). The bid price to use after the pairing is $10/GJ for both the 10am and 2pm schedules (compared with the previously used bid prices of $20/GJ and $30/GJ). TABLE AN EXAMPLE OF AP CLAWBACK (STEPS 1 AND 2) Schedule 6AM 10AM 2PM 6PM 10PM Total daily Initial AP calculations Bid price ($/GJ) $10.0 $20.0 $30.0 $250.0 $35.0 Market price ($/GJ) $8.0 $8.0 $7.0 $7.0 $6.0 OS GJ Change in CUIQ GJ Initial AP $ $20.0 -$ $46.00 $0.00 $0.00 -$86 AP clawback step 1 & 2 Bid price use for $10.0 $10.0 $10.0 $250.0 $35.0 revised AP Revised AP $ $20.0 -$10.0 -$6.0 $0.0 $0.0 $4 47

51 SECTION 14 Ancillary payments The example in Table illustrates step 3 of the AP clawback algorithm. Details of the calculations are as follows: there are 2 bid steps for the 10am schedule (the data in bid step 1 is shown in Table 14.10); the change in CUIQ is -5 GJ and 10 GJ for bid step 1 and 2 respectively; the initial AP for the schedule is $40 ( sum of bid steps 1 and 2); the revised AP for bid step 1 is reduced to -$10 after adjustments in clawback steps 1 and 2. There is no change to the initial AP for bid step 2. The revised AP for the schedule has thus increased from $40 to $90. This means that MPs need to fund $50 of additional AP. Some negative AP will be re-instated; the AP rate is equal to the total revised AP divided by the greater of the total positive and negative CUIQ ( = $90/max(5 GJ,10 GJ)); a total of -$45 of negative AP is re-instated to bid step 1; the re-instated negative AP is added back to the revised negative AP in bid step 1. The final AP is therefore -$55 (= max (-$60, -$45 -$10)) which is of the greater of the AP values before and after the corrections; and the total AP for the schedule after adjustment for clawback is $45.0)) which is of the greater of le of AP clawback (steps 3) TABLE AN EXAMPLE OF AP CLAWBACK (STEPS 3) 14.4 The AP flip flop algorithm Winter 2007 (the first winter of the ex-ante market) saw a number of gas days with large positive APs in the early schedules, which were followed with large negative APs in the subsequent schedules. In some cases, the negative APs were large enough to completely cancel the large positive APs. When a positive AP occurs as a result of congestion in the transmission system, MPs who cause it are required to fund the positive AP via positive uplift payments to the market. However, when system congestion is relieved resulting in negative APs, money is returned to MPs via negative uplift payments. It is possible that MPs who cause system congestion in the early schedules (and pay uplift charges to the market) are not those who receive money from the market in the subsequent schedules when the system congestion is resolved. The AP flip flops may create an issue of equity in the market. A mechanism was introduced to minimise the swings in total market APs from schedule to schedule while not changing the total APs paid to each MP over the gas day. To the extent possible, the flip-flop mechanism systematically cancels out negative APs with related positive APs to minimise the uplift amounts. The AP flip flop algorithm applies to total APs for each schedule (ie sum of total injection and withdrawal APs) which have already been adjusted for AP clawback, and determines the total uplift payments to be allocated to the responsible MPs. The AP flip flop adjustments involve the following steps. Bid 1 Bid 2 Total Change in CUIQ GJ Initial AP -$60 $100 $40 Revised AP (after -$10 $100 $90 clawback step 1 & 2) AP rate $/GJ $9 Re-instated negative AP -$45 $0 AP -$55 $100 $45 48

52 SECTION 14 Ancillary payments Step 1 Assign groupings to consecutive schedules of AP with the same sign The injection and withdrawal APs for all MPs are summed for each schedule (TAP). Consecutive schedules of revised APs with the same sign are assigned to the same group. For the purpose of assigning groupings, schedules with 0 APs are grouped with those with positive APs. Step 2 Cancel negative revised APs with positive revised APs in preceding schedules Total negative APs are used to cancel as much of the positive APs as possible. Negative APs can only be used to cancel positive APs in the preceding schedules. Depending on the magnitude of the positive and negative APs in each combination, the residual APs (resulting from cancellations of positive APs with negative APs) can be 0, positive or negative. Step 3 - Apportion residual APs This step involves apportioning the residual AP (obtained in step 2) in each group to each schedule in that group according each schedule s share of the total revised AP (TAP). An example of AP flip flop Table shows how the AP flip flop method is applied to smooth out the volatility of APs in related schedules while still allocating costs to cause. Details of the calculations are explained below. the revised APs are assumed to be $900, -$400, -$800, $200 and $0; based on the sign of the APs, the assigned groupings are 1, 2, 2, 3 and 3 for schedules 1 to 5 respectively; the negative APs in the 10am and 2pm schedules can be used to reduce the positive AP in the 6am schedule and there are no possible cancellations of APs for the 6pm and 10pm schedules. This reduces the total APs for the 10am and 2pm schedules to $0 and results in a negative residual AP of -$300 in the 2pm schedule; the final AP is -$100 and -$200 for the 10am and 2pm schedules respectively after apportioning the residual AP; and the total AP for the gas day remains unchanged at $100. TABLE AN EXAMPLE OF AP FLIP FLOP Schedule 6AM 10AM 2PM 6PM 10PM Total daily Total revised AP (adjusted for AP clawback) $900 -$400 -$800 $200 $0 -$100 AP grouping (step 1) Total AP (adjusted for AP flip flop step 2) 0 0 -$300 $200 $0 -$100 Total AP (adjusted for AP flip flop step 3) $0 -$100 -$200 $200 $0 -$100 49

53 SECTION 15 Uplift hedge and authorised maximum interval quantity 15.1 The uplift hedge process An uplift hedge (UH) is the amount of authorised MDQ and AMDQ credit certificates which an MP nominates to use as hedges against congestion uplift. The nominated quantity of authorised AMDQ or AMDQ credit must be supported by scheduled injections from the relevant source of gas supply. The nominated quantity can either be used as an uplift hedge or to qualify for an AP but not both at the same time. The UH is converted to interval quantities (for each scheduling interval) - the AMIQ uplift hedge -using the MP s nominated AMIQ profile. For the purpose of calculating UH, injection points are grouped into close proximity injection points (CPP). For example, injections under various contracts at VicHub and Longford are considered to be injected from the Longford injection point. Likewise, injections from various sources at Iona (for example, SEA Gas and Iona underground storage) are all deemed to be from Iona. Figure 15.1 outlines the process for calculating AMIQ uplift hedge. FIGURE 15.1 UPLIFT HEDGE AND AMIQ UPLIFT HEDGE PROCESS Longford CPP Start Non Longford CPP Tariff authorised MDQ Calculate diversified D authorised MDQ = authorised D MDQ *diversity factor Calculate diversified site AMDQ credit = AMDQ credit nom *diversity factor Site AMDQ credit nomination Hub and Tariff V authorised MDQ Calculate AMDQ = diversified D + Hub and Tariff V authorised MDQ Calculate AMDQ credit = diversified site + hub AMDQ credit nomination Hub AMDQ credit nomination AEMO SETTLEMENTS Calculate Longford injection hedge and Agency injection hedge Calculate Longford uplift hedge = min (AMDQ, Longford injection and agency injection hedge) Calculate non- Longform uplift hedge = min (AMDQ credit, non- Longford injection and agency injection hedge) Calculate Non- Longford injection hedge and agency injection hedge Aggregate Longford and Non-Longford Uplift hedge Calculate AMIQ uplift hedge Nominate AMIQ profile Stop 50

54 SECTION 15 Uplift hedge and authorised maximum interval quantity NOTE See Appendix 4 for a detailed diagrammatic representation of the AMIQ process. The calculations involve the following steps. Step 1: For each injecting MP, calculate the diversified tariff D authorised MDQ and diversified site AMDQ credit at each CPP. Since not all customers demands peak at the same time a (load) diversity factor is calculated for each tariff D site. The AMDQ load diversity factor for a site is the ratio which compares the average authorised gas usage at that site on selected system peak days and its site authorised MDQ or AMDQ credit certificates. The diversified tariff D authorised MDQ relate to the Longford CPP whereas AMDQ credits are summed for each non Longford CPP. Step 2: Calculate AMDQ and AMDQ credit for each MP injecting at each Longford and Non-Longford CPP. Longford AMDQ is equal to the sum: of all diversified tariff D authorised MDQ of that MP s customers; plus that MP s allocated share of tariff V authorised MDQ ; plus authorised MDQ held by the MP at the hub, if any. Injection hedge (IH) = minimum (injection hedge nomination, scheduled injection) Step 4: calculate uplift hedge at each CPP For the Longford CPP, the uplift hedge is equal to the lesser of: Authorised MDQ; and the sum of Longford CPP IH and AIH. For each non-longford CPP, the uplift hedge is equal to the lesser of: AMDQ credit; and the sum of non-longford IH and AIH. Step 5: calculate total uplift hedge Total uplift hedge = UH for Longford CPP + UH for all non-longford CPP Non-Longford AMDQ credits are equal the sum of : the diversified AMDQ credit assigned to that MP s customers sites; plus AMDQ credit nominations assigned to the hub, if any. Step 3: Calculate Injection Hedge (IH) and Agency Injection Hedge (AIH) Injection hedge (IH) and Agency Injection Hedge (AIH) are calculated based on injection hedge and agency hedge nominations submitted by MPs via the WebExchanger (see section 8.5). These nominations need to be supported by scheduled injections from the relevant injection points. In determining IH and AIH, priority is given to meet MP s own IH nomination; and if there are sufficient gas injections to support the AIH nominations each MP receiving the AIH nomination will be allocated a share of the remaining scheduled injections on either a preferred or pro-rata basis according to the information provided by the AIH provider. 51

55 SECTION 15 Uplift hedge and authorised maximum interval quantity 15.2 An example of uplift hedge calculation The example in Table 15.1 shows how uplift hedge is calculated and assumes that the given MP: has 80 GJ of Longford diversified authorised MDQ, 70 GJ of allocated tariff V Block authorised MDQ and 95 GJ of diversified AMDQ credit; is scheduled to inject 125 GJ from Longford and 35 GJ from a non-longford CPP; has nominated to use 110 GJ and 10 GJ of the Longford scheduled injections as Longford IH and Longford AIH, and 10 GJ of non-longford scheduled injections as non-longford IH. All nominations are approved because there are sufficient scheduled injections to support them. The total Uplift hedge is therefore 130 GJ being the sum of 120 GJ and 10 GJ from Longford and non-longford CPP respectively Authorised maximum interval quantity MPs who intend to use their uplift hedges against congestion uplift are required to assign percentages which are used to calculate the authorised maximum interval quantity (AMIQ) for each scheduling interval. The AMIQ profile is submitted by MPs at the BoD schedule and is fixed for that gas day. AMIQ profiles are subject to a set of maximum limits that can be assigned for each scheduling interval. These limits are set based on a winter peak day demand profile defined in AEMO s system planning criteria. If the submitted profile for the gas day is outside the allowable limits they will be rejected. The relevant MP(s) will receive a notice provided via the WebExchanger about errors in the submitted profile and re-submit the information if they wish to do so. Table 15.2 summarises the upper % limits on MPs submitted AMIQ profiles. There are no lower limits on the nominated AMIQ profiles. The upper limits are set out as follows: 25.8% for scheduling intervals between 6pm and 10pm; 41.8% for scheduling intervals between 2pm and 10pm; and 78.4% for scheduling intervals between 6am and 10pm. TABLE UPLIFT HEDGE CALCULATION Close proximity point (CPP) Longford Non- Longford Calculate Authorised MDQ (1) Diversified Authorised MDQ or AMDQ credit and AMDQ credits (2) tariff V Auth MDQ share 70.0 (3) Total AMDQ or AMDQ credits = (1) + (2) Calculate Injection and (4) OS injection Agency Injection Hedge (5) Injection hedge nomination (6) Injection hedge = (Min((4), (5))) (7) Agency injection hedge nomination (preferred basis) (8) Agency injection hedge = (max(0, min ((7), (4) (5)) Calculate Uplift Hedge (9) Uplift hedge = ((6) + (8)) (10) Total Uplift hedge

56 SECTION 15 Uplift hedge and authorised maximum interval quantity TABLE 15.2 AMIQ PROFILE LIMITS Limits on MP s AMIQ profile Scheduling interval beginning Limits imposed 6am 10am 2pm 6pm 10pm 12pm Maximum 100% Maximum 78.4% 42.6% Maximum 42.6% 41.8% 42.6% Maximum 25.8% 25.8% 25.8% 25.8% 42.6% Minimum 0% 0% 0% 0% 0% The AMIQ for each scheduling interval is calculated by apportioning the total uplift hedge in accordance with the MP s nominated AMIQ profile as shown in Step 6 of the Uplift hedge and AMIQ process. Step 6: calculate AMIQ The AMIQ Uplift hedge is calculated by applying the MP s nominated AMIQ profile to the sum of Longford and non-longford uplift hedges. AMIQ Uplift hedge = (Longford uplift hedge + non- Longford uplift hedge) * AMIQ profile An example of AMIQ calculations Table 15.3 illustrates how AMIQ is derived from uplift hedge and the nominated AMIQ profile from the MP. In this example, the total Uplift Hedge supported by scheduled injections is 130 GJ and is apportioned to each scheduling interval according to the MP s submitted AMIQ profile which complies with the maximum AMIQ limits shown in Table TABLE 15.3 AMIQ AMIQ profile AMIQ 6AM - 10AM 18% AM - 2PM 16% PM - 6PM 15% PM - 10PM 25% PM - 6AM 26% 33.8 Total 100% Appendix 4 contains a detailed diagrammatic representation of AMIQ. 53

57 SECTION 16 Uplift payments This chapter explains the concept of uplift payments (UPs) and provides numerical examples showing how they are calculated The uplift payment process To the extent possible, uplift is charged to MPs whose actions cause the APs. Accordingly, the total UPs paid by the responsible MPs should equal the total APs made to MPs who are eligible for these latter payments. Uplift is generally paid by MPs but in special circumstances the Transmission Pipeline Operator (TPO) may have to pay a component. Figure 16.1 shows the process for allocating uplift under the following categories: surprise uplift which is charged to MPs who deviate from their scheduled injections or controllable/ uncontrollable withdrawals in the previous schedule, or change their demand forecasts in the following schedule; congestion uplift which is charged to MPs who cause system congestion because their scheduled withdrawals exceed their AMIQ uplift hedge (AMIQ); TPO congestion uplift which is allocated to the TPO where it can be determined that the TPO has contributed to congestion by not making available the relevant plant and the associated pipeline capacity as required under the SEA; and common uplift which cannot be allocated to any MPs, for example costs associated with AEMO s excessive demand forecast overrides. These costs are socialised across MPs who withdraw gas on the relevant gas day. The key input data to UP calculations include: ancillary payments (see chapter 14 for more details); authorised maximum interval quantity (AMIQ) (see section 15.3); and MP s effective demand forecasts (see section 16.2). FIGURE 16.1 CALCULATIONS OF UPLIFT PAYMENTS Start Ancillary payments calculations Uplift hedge calculations Service Envelope Agreement (SEA) not met? YES Calculate TPO congestion uplift AEMO SETTLEMENTS Calculate MP effective demand forecasts Actual injection and withdrawals NO Calculate MP uplift GJ *surprise (if any) *congestion (if any) *common Calculate uplift payments *surprise (if any) *congestion (if any) *common Stop 54

58 SECTION 16 Uplift payments 16.2 AEMO s demand forecast overrides and Market participants effective demand forecasts MPs who supply to uncontrollable loads must submit hourly forecasts of these loads to AEMO. AEMO compares the aggregated uncontrollable demand forecasts from all MPs with its own demand forecast for each hour of the gas day. AEMO must intervene if it determines that the differences between the two sets of forecasts are too large compared to the set thresholds. In this event, AEMO will apply positive (or negative) hourly demand overrides and adjust each MP s hourly demand forecasts by an appropriate quantity to bring the MPs demand forecasts within the tolerance level for demand forecast differences. MPs adjusted demand forecasts are termed effective demand forecasts. NOTE MPs effective demand forecasts are only used for calculating congestion and surprise uplift quantities and do not affect their deviation and imbalance quantities and payments. AEMO will only adjust MPs demand forecasts for a given hour if: the override for that hour is positive; and the sum of the hourly demand overrides within the relevant scheduling interval is also positive. LINK Available from the AEMO website at AEMO follows the prescribed procedures set out in the document Demand override methodology when applying overrides to MPs demand forecasts. Gas Market Operations > Scheduling Information Calculation of AEMO s adjusted hourly demand forecast overrides Table 16.1 shows how AEMO s demand forecast overrides are adjusted to produce MPs effective demand forecasts. This particular example relates to the 6am-10am scheduling interval and assumes that: AEMO s hourly demand forecasts exceed the aggregated MPs demand forecasts for each hour between 7am and 10am such that demand forecast overrides are required for these hours (see column A) The total positive demand forecast difference (or demand forecast override) for the scheduling interval is +3 GJ (see column A); MPs demand forecasts for the first hour will not be adjusted because they are higher than AEMO s forecast. The demand forecast override for this hour is therefore 0 (see Column C); and the total positive demand forecast override is 3GJ for the scheduling interval and is apportioned to each hour with positive demand forecast difference according to their share of the total positive demand forecast override (column B) as shown in column C. TABLE 16.1 AEMO S ADJUSTED DEMAND FORECAST OVERRIDES Scheduling interval Hour Hourly demand forecast difference A % of positive demand forecast override B Adjusted hourly demand forecast override C 6AM - 10AM 6AM - 7AM % 0.0 6AM - 10AM 7AM - 8AM % AM - 10AM 8AM - 9AM % AM - 10AM 9AM - 10AM % AM - 10AM Total %

59 SECTION 16 Uplift payments Calculations of MPs effective demand forecasts AEMO s adjusted hourly demand forecast overrides are allocated: to each MP s hourly demand forecasts for the purposes of calculating their effective demand forecasts, which are in turn used for determining congestion and surprise quantities; and in proportion of their share of the total positive forecast deviations for that hour. Columns A to C in Table 16.2 show the hourly forecast and actual demands, and the demand forecast deviations for the 6am 10am scheduling interval for a given MP. Its share of the total (positive) deviations is calculated in column E. The adjustment to the MPs hourly forecasts (column G) is the lesser of the MP s positive deviation (column C) and its share of AEMO s adjusted demand forecast overrides (calculated by applying the MP s % proportion in column E to the override values in column F). The effective demand forecast is in Column H. in the first hour (6am to 7am), the MP exceeds its forecast and is in fact responsible for all of the deviation for that hour. However, as no demand forecast override applies to this hour, there is no adjustment to the MP s forecast; in the second hour (7am to 8am), the MP s deviation is negative and so this MP cannot be allocated any share of the positive demand forecast override. The total AEMO demand forecast override is 0.8 GJ and is allocated to other MPs who have (positive) deviations if there are any. If no MPs deviate positively from their demand forecasts the unallocated AEMO demand forecast overrides will be included in the common uplift quantities; the MP has (positive) deviations in the third (8am to 9am) and fourth (9am to 10am) hours. The demand forecasts for these hours are adjusted upward by a quantity which equals the lesser of the MP s positive deviation and its share of the aggregate (positive) deviations. The adjustments to the MP s demand forecasts for these hours are 0.9 GJ and 0.4 GJ; and the effective demand forecast for the MP for the BoD scheduling interval is 32.3 GJ and is slightly lower than its actual demand of 32.2 GJ. TABLE 16.2 CALCULATION OF AN MP S EFFECTIVE DEMAND FORECAST Scheduling interval Time interval MP s demand forecasts A MP s actual uncontrollable withdrawal B MP s demand forecast deviation C = max (0,B - A) Total MPs demand forecast deviation D Proportion of total demand forecast deviation E = C/D AEMO adjusted demand forecast overrides F Adjustment to MP demand forecasts G =min (C, E * F) Effective demand forecasts H = G + A 6AM - 10AM 6AM - 10AM 6AM - 10AM 6AM - 10AM 6AM - 10AM 6AM - 7AM % AM % AM 8AM % AM 9AM % AM Total For more details about calculations of AEMO s demand forecast overrides and MPs effective demand forecasts see the document Uplift payment functional design on the AEMO website. 56

60 SECTION 16 Uplift payments 16.3 TPO congestion uplift TPO congestion uplift is allocated to the TPO for any shortfall in system capacity due to a breach of the Service Envelope Agreement (SEA). For example, this could be due to additional congestion resulting from an unplanned outage of a critical plant where that outage could be attributed to lack of maintenance of the plant in accordance with the SEA. For the purpose of calculating TPO congestion uplift, a shortfall in system capacity is treated as an AMIQ exceedance caused by the TPO. The method for calculating MPs congestion uplift is used to allocate TPO congestion uplift (see section 16.4 for more details). TPO congestion uplift is limited to a maximum of $20/GJ for any scheduling interval and $1 million for any given year. If these limits are exceeded the unallocated TPO congestion uplift will be added to the relevant common uplift and allocated to all MPs according to the common uplift allocation method (see section for more details) Calculations of market participant s uplift quantity The total AP in each schedule is allocated to surprise, congestion and common uplift based on the GJ quantities determined for each of these categories. This section explains the methods used for calculating these quantities using numerical examples Surprise uplift quantity An MP is liable for surprise uplift if it: deviates from its scheduled quantities (injections and withdrawals) in the previous schedule; and/or revises its demand forecasts and/or scheduled controllable withdrawals in the current schedule. For the first schedule of the gas day, the surprise uplift quantity is calculated from deviation quantities for the 10pm 6am SI of the previous gas day as follows: Surprise uplift quantity (s=1) = (actual uncontrollable withdrawal effective demand forecasts)(0) + (actual controllable withdrawal scheduled withdrawal)(0) (actual injection scheduled injection)(0) s=1 denotes the 6am schedule (0) denotes the 10pm-6am SI of the previous gas day For the subsequent re-schedules, the surprise uplift quantity is the sum of the total deviation quantities in the previous scheduling interval plus changes in effective demand forecasts and scheduled controllable withdrawals for the current schedule: Surprise Uplift quantity (s>1) = (actual uncontrollable withdrawals effective demand forecasts)(si-1) + actual controllable withdrawal scheduled withdrawal)(si-1) (actual injection scheduled injection)(si-1) + change in effective demand forecasts(s) + change in scheduled controllable withdrawals(s) Surprise uplift quantities can be positive or negative. Positive and negative uplift quantities are associated with positive and negative AP allocations respectively. An example of calculations of surprise uplift quantities Table 16.3 shows calculations of surprise UP quantity (shown in column C) for an MP. Injection deviations (column A) are those calculated previously in Table The numbers in column B include deviations in effective demand forecasts and controllable withdrawals, and changes in demand forecast and controllable withdrawals between schedules. Columns D and E display the calculated positive and negative surprise uplift quantities separately. 57

61 SECTION 16 Uplift payments TABLE 16.3 CALCULATION OF SURPRISE UPLIFT QUANTITY Schedule Injection deviations A Withdrawal deviations + change in forecasts B Surprise uplift C = B - A Positive surprise uplift D Negative surprise uplift E 6AM AM PM PM PM Table 16.4 shows how deviations and changes in effective demand forecasts are calculated for each schedule. The same approach applies to calculating the adjusted deviations for controllable withdrawals. The values shown in blue in the table denote the deviations in effective demand forecasts and those in red are the calculated changes in effective demand forecasts between schedules. These values are calculated from the actual demand and effective demand forecasts. Consider the 6am schedule, the surprise uplift quantity associated with uncontrollable withdrawals is 1 GJ and is equal to the difference between the actual demand (30 GJ) and the effective demand forecast (29 GJ) for the 10pm-6am SI of the previous gas day. Since this is the first schedule of the gas day, there are no changes in demand forecasts. For the 10am schedule, the surprise uplift quantity associated with uncontrollable withdrawals is -7 GJ. This is the sum of: -4 GJ (= 28 GJ - 32 GJ) due to deviation in demand forecasts at the 6am schedule; and -3 GJ (= -1 GJ -1 GJ -1 GJ + 0 GJ) which is the sum of the downward revisions to the demand forecasts for the 4 scheduling intervals after 10am. The surprise uplift quantities are 0 GJ, -1 GJ and -1 GJ for the 2pm, 6pm and 10pm schedules respectively. TABLE 16.4 SURPRISE UPLIFT QUANTITY ASSOCIATED WITH WITHDRAWALS Scheduling interval Actual Effective demand forecasts by schedule Surprise uplift quantity 10PM 6AM 10AM 2PM 6PM 10PM 6AM 10AM 2PM 6PM 10PM 10PM - 6AM AM - 10AM AM - 2PM PM - 6PM PM - 10PM PM - 6AM Total

62 SECTION 16 Uplift payments Congestion uplift quantity If: an MP is scheduled to withdraw a quantity of gas in a given scheduling interval which exceeds its AMIQ for that scheduling interval; and the system is congested resulting in positive AP, it must pay congestion uplift charge (see section 15.3 for more details about AMIQ). AMIQ exceedance or congestion uplift quantity for a given scheduling interval is calculated according to the following formula: AMIQ exceedance = Max (0, effective demand forecasts + scheduled withdrawals AMIQ) The congestion uplift quantity for; the BoD schedule is the sum of the AMIQ exceedance for all the scheduling intervals included in that schedule; and the re-schedules is the sum of the changes in AMIQ exceedance for each relevant scheduling interval between the successive schedules. Table 16.5 shows how AMIQ exceedance quantities are calculated for a gas day using: the AMIQ information shown in Table 15.3; the effective demand forecasts and scheduled controllable withdrawals (assumed 0 in this case); and the AMIQ exceedance and change in AMIQ exceedance calculated from the above data. The congestion uplift quantities are 19.6 and -2.0 GJ for the 6am and 10am schedules respectively, and 0 GJ for all subsequent schedules. TABLE 16.5 CALCULATIONS OF AMIQ EXCEEDANCE Scheduling interval AMIQ Effective demand forecasts and scheduled controllable withdrawals 6 AM 10 AM 2 PM 6 PM 10 PM 6 AM AMIQ exceedance 6AM - 10AM NA 10AM - 2PM PM - 6PM AM 2 PM 6 PM 10 PM 10 AM Change in AMIQ exceedance 6PM - 10PM PM - 6AM Total daily PM 6 PM 10 PM Congestion uplift quantities can be positive or negative. Positive (or negative) quantities are used for allocating positive (or negative) AP. Table 16.6 shows the positive and negative congestion uplift quantities for the given MP and the total quantities for all MPs (assumed 2 in this example). This data will be used for calculating congestion uplift payments. 59

63 SECTION 16 Uplift payments TABLE 16.6 CONGESTION UPLIFT QUANTITY Schedule Positive Congestion MP Negative Congestion Positive Congestion Total all MPs Negative Congestion 6AM AM PM PM PM Common uplift quantity Common uplift quantity is AEMO s residual demand forecast override which cannot be allocated to any MP or causers. This data is used for calculating common UPs which will be apportioned to all withdrawing MPs. Table 16.7 summarises the three types of uplift quantities - surprise, congestion and common - which form the basis for allocating APs (or calculating UPs). TABLE 16.7 TOTAL UPLIFT QUANTITIES Surprise Uplift Congestion Uplift AEMO residual override Total Uplift Schedule Positive Negative Positive Negative Positive Negative Positive Negative 6AM AM PM PM PM Uplift payments The total AP for each schedule will be allocated to the three types of UP based on the calculated uplift quantities shown in Table Each type of UP will be apportioned to each MP according to the allocation methods explained below Allocations of ancillary payments by type of uplift The total AP is apportioned to each type of uplift according to the calculated uplift proportions which are derived from the quantities in Table It should be noted that common UPs also include: the amount of TPO congestion Uplift payments in excess of their liability limits; and any residual APs after all types of UPs have been appropriately allocated to the causers. The following examples assume there are no residual TPO and residual APs to be allocated to MPs. The common UP therefore only includes uplift costs due to AEMO s residual demand forecast overrides. Positive and negative APs are allocated separately and apportioned to each type of uplift according to their share of the total Uplift quantities summarised in Table

64 SECTION 16 Uplift payments TABLE 16.8 PROPORTIONS OF UPLIFT QUANTITIES Surprise Uplift (% total) Congestion Uplift (% total) Common Uplift (% total) Total Uplift (%) Schedule Positive Negative Positive Negative Positive Negative Positive Negative 6AM 22% 0% 78% 0% 0% 100% 100% 100% 10AM 0% 50% 0% 33% 100% 17% 100% 100% 2PM 0% 100% 25% 0% 75% 0% 100% 100% 6PM 93% 50% 7% 0% 0% 50% 100% 100% 10PM 33% 100% 0% 0% 67% 0% 100% 100% Table 16.9 shows the apportionment of the APs to each type of Uplift based on the proportions in Table TABLE 16.9 ALLOCATIONS OF ANCILLARY PAYMENTS BY TYPE OF UPLIFT Surprise uplift Congestion uplift Common uplift Total ancillary (uplift payments) Schedule Positive Negative Positive Negative Positive Negative Positive Negative 6AM $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 10AM $0.0 -$52.4 $0.0 -$31.7 $0.0 -$15.9 $0.0 -$ PM $0.0 -$200.0 $0.0 $0.0 $0.0 $0.0 $0.0 -$ PM $186.7 $0.0 $13.3 $0.0 $0.0 $0.0 $200.0 $0.0 10PM $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $ Allocations of uplift payments to market participants For each schedule, the total UP for each type of uplift is apportioned to each MP according to each MP s share of the: total positive or negative surprise uplift quantity for that schedule surprise Uplift (see Table 16.10); total positive or negative congestion quantity for that schedule congestion Uplift (see Table 16.11); total daily actual withdrawals common uplift (see Table 16.12). TABLE ALLOCATIONS OF SURPRISE UPLIFT PAYMENTS TO MARKET PARTICIPANTS Positive Surprise Uplift payments Negative Surprise Uplift payments Schedule Total Surprise UP A MP B share of total B MP B payments C = A * B Total Surprise UP D MP B share of total E MP B payments F = D * E MP B total payments G = C + F 6AM $ % $0.0 $ % $0.0 $0.0 10AM $ % $0.0 -$ % -$52.4 -$52.4 2PM $ % $0.0 -$ % -$66.7 -$66.7 6PM $ % $186.7 $ % $0.0 $ PM $ % $0.0 $ % $0.0 $0.0 61

65 SECTION 16 Uplift payments TABLE ALLOCATIONS OF CONGESTION UPLIFT PAYMENTS TO MARKET PARTICIPANTS Positive Congestion Uplift payments Negative Congestion Uplift payments Schedule Total Congestion UP A MP B share of total B MP B payments C = A * B Total Congestion UP D MP B share of total E MP B payments F = D * E MP B total payments G = C + F 6AM $0.0 81% $0.0 $0.0 0% $0.0 $0.0 10AM $0.0 0% $0.0 -$ % -$31.7 -$31.7 2PM $0.0 0% $0.0 $0.0 0% $0.0 $0.0 6PM $13.3 0% $0.0 $0.0 0% $0.0 $0.0 10PM $0.0 0% $0.0 $0.0 0% $0.0 $0.0 TABLE ALLOCATIONS OF COMMON UPLIFT PAYMENTS TO MARKET PARTICIPANTS Schedule MP s actual withdrawal A Total all MP actual withdrawal B MP B proportion of actual withdrawals C = A/B Total Common UP ($) D MP B Common UP ($) E = C * D 6AM % $0.0 $0.0 10AM % -$15.9 -$8.5 2PM % $0.0 $0.0 6PM % $0.0 $0.0 10PM % $0.0 $0.0 62

66 Appendix 1 Glossary Allocation Agent A person who has been appointed by a market participant to submit injection allocation statements or withdrawal allocation statements under clauses 229 or 230 of the NGR. AMDQ Authorised Maximum Daily Quantity. Augmentation The process of upgrading the capacity or service potential of a transmission (or a distribution) pipeline. Bid A bid by a Market participant in accordance with Part 19 Division 2 Subdivision 2 of the NGR to inject quantities of gas into, or withdraw quantities of gas from, the transmission system during a gas day, or as modified by that Market participant in accordance with Part 19 Division 2 Subdivision 2 of the NGR. Bid stack Incremental gas quantities by injection point, offered by market participants and stacked in price order. BassGas A project which sources gas from the Bass Basin for supply to the DTS and is injected at Pakenham. BoD Linepack Beginning-of-day linepack (BoD LP) is equal to the EoD LP from the previous gas day. See also EoD Linepack. Compensation guidelines Guidelines developed by AEMO in accordance with clause 237(10) of the NGR, which describe the principles and methodology upon which the compensation panel should base its determination of amounts payable under clause 238 in relation to claims for compensation. Connection point A delivery point, transfer point, or receipt point. Constraint Any limitation causing some defined gas property (such as minimum pressure) to fall outside its acceptable range. Culcairn The transmission system interconnection point between Victoria and New South Wales. Customer Any party who purchases gas and consumes gas at particular premises. Customers can deal through retailers or may choose to become market participants in their own right, and take on the retailing functions themselves. Delivery point The point on a pipeline gas is withdrawn from and delivered to a customer or injected into a storage facility. Distribution The transport of gas over a combination of high pressure and low pressure pipelines from a City Gate to customer delivery points. Distribution pipeline Pipelines for the conveyance of gas that: Distributor Declared Transmission System (DTS) Declared Transmission System (DTS) constraint EoD Linepack Ex-Ante have a maximum allowable operating pressure of 515 kpa or less; or where the maximum operating pressure is greater than 515 kpa, are uniquely identified as a distribution pipeline in a distributor s access arrangement. The owners of the distribution pipelines, which transport gas from the transmission pipelines to the consumer or customer. Owned by APA Group and operated by AEMO, the Declared Transmission System serves Gippsland, Melbourne, Central and Northern Victoria, Albury, the Murray Valley region, Geelong and extends to Port Campbell. A constraint on the DTS. See also constraint. End-of-day linepack (EoD LP) is measured at the end of a gas day at 6 am. EoD LP is equal to the BoD LP for the next gas day. Before the event. 63

67 Appendix 1 Glossary Expansion Extension Gas day Injection Interconnect (The) Linepack LNG Market information bulletin board (MIBB) Market customer Market, gas market Market participant Maximum daily quantity (MDQ) Market prices Maximum hourly quantity (MHQ) MIRN MSOR, M & S O Rules Natural gas Participant Peak shaving Pipeline Pipeline injections Price (bid) step Reference hub Retailer An increase in the capacity or service potential of a transmission pipeline or a distribution pipeline by: (a) replacing or enhancing existing plant or equipment; or (b) adding new plant or equipment. A new pipeline built to enlarge the area to which gas may be, or is, supplied, including (for the avoidance of doubt) extensions which: (a) connect together pre-existing pipeline systems, or (b) extend the supply of gas at transmission pressure within a distribution area. A period of 24 consecutive hours beginning at 6:00 am. The physical injection of gas into the transmission system. Refers to the pipeline from Barnawartha to Wagga Wagga, connecting the Victoria and New South Wales transmission systems. The point of connection is at Culcairn. This does not include the VicHub (Longford) and SEA Gas (Iona) interconnections. The pressurised volume of gas stored in the pipeline system. Linepack is essential for gas transportation through the pipeline network throughout each day, and is required as a buffer for within-day balancing. Liquefied natural gas. The Melbourne LNG storage facility is located at Dandenong. A facility established by AEMO on the electronic communication system on which it may publish information for market participants. A gas customer who is a market participant. A market administered by AEMO for the injection of gas into, and the withdrawal of gas from, the transmission system and the balancing of gas flows in or through the transmission system. A party who is eligible, by registration with AEMO, to trade gas on the spot market by submission of nominations and inc/dec offers to AEMO in accordance with the NGR. Maximum daily quantity (of gas supply or demand). Prices for gas set by AEMO for each scheduling horizon as determined in accordance with Part 19 Division 2 Subdivision 3 of the MSO Rules. Maximum hourly quantity (of gas supply or demand). Metering Installation registration number The Victorian Gas Industry Market and System Operations Rules. A naturally occurring hydrocarbon composed of between 95 and 99% methane (CH4), the remainder predominantly being ethane (C2H6). A person registered with AEMO in accordance with the NGR. Meeting the demand peak using injections of vaporised LNG. A pipe or system of pipes for or incidental to the conveyance of gas and includes a part of such a pipe or system. The injection of gas into a pipeline. A price and quantity, in accordance with clause 209(5) of the NGR, defining the quantity of gas that a Market participant, if scheduled by AEMO, inject into or withdraw from the transmission system. A Common point of reference within the gas transmission system established for the purpose of valuing authorised MDQ and AMDQ credit certificates. Those selling the bundled product of energy services to the customer. 64

68 Appendix 1 Glossary Retail Gas Market Rules Scheduling SEA Gas Pipeline SEA Gas Interconnect Service Envelope Agreement (SEA) South West Pipeline (SWP) Storage facility System capacity System constraint System injection point System withdrawal point System withdrawal zone (SWZ) tariff D tariff V Rules made under the Gas Industry Act in relation to the retail gas market. The process of scheduling nominations and increment/decrement offers, which AEMO is required to carry out in accordance with the NGR, for the purpose of balancing gas flows in the transmission system and maintaining the security of the transmission system. The 680 km pipeline from Port Campbell to Adelaide connected to the Minerva plant, and the DTS and the UGS at Iona. Principally constructed to ship gas to South Australia. The new Interconnection between the SEA Gas pipeline and the DTS at Iona. An agreement entered between AEMO and a Transmission Pipeline Owner, as required under clause 327 of the NGR, pursuant to which the Transmission Pipeline Owner agrees to provide to AEMO gas transportation services and pipeline capacity in respect of that Transmission Pipeline Owner s pipelines and, which, for the avoidance of doubt, may be part of an agreement between AEMO and the Transmission Pipeline Owner which relates also to other matters. The 500 mm pipeline from Lara (Geelong) to Iona. A facility for storing gas, including the LNG storage facility and the Iona UGS. The maximum demand that can be met on a sustained basis over several days given a defined set of operating conditions. System capacity is a function of many factors and accordingly a set of conditions and assumptions must be understood in any system capacity assessment. These factors include: load distribution across the system; hourly load profiles throughout the day at each delivery point; heating values and the specific gravity of injected gas at each injection point; initial line pack and final line pack and its distribution throughout the system; ground and ambient air temperatures; minimum and maximum operating pressure limits at critical points throughout the system; and powers and efficiencies of compressor stations. See Declared Transmission System (DTS) constraint. A transmission system connection point designed to permit gas to flow through a single pipe into the transmission system, which may also be, in the case of a transfer point, a system withdrawal point. A transmission system connection point designed to permit gas to flow through a single pipe out of the transmission system, which may also be, in the case of a transfer point, a system injection point. Part of the transmission system which contains one or more system withdrawal points and in respect of which AEMO has determined that a single withdrawal nomination or a single withdrawal increment/decrement offer must be made. The transportation tariff applying to daily metered sites with annual consumption > 10,000 GJ or MHQ > 10 GJ and that are assigned as tariff D in the AEMO meter installation register. Each site has a unique meter ID number (MIRN). The transportation tariff applying to non-tariff D load sites. This includes residential and small to medium-sized commercial and industrial gas users. 65

69 Appendix 1 Glossary Transfer agent Transferee Transferor Transmission Transmission customer Transmission pipeline Transmission pipeline owner Transmission system Unaccounted for gas (UAFG) Underground Gas Storage (UGS) VicHub VoLL Western Transmission System (WTS) A person or organisation duly appointed by Transferors to act on their behalf for the purpose of making application to AEMO for the transfer of authorised MDQ or AMDQ credit certificates. The recipient of transferred authorised MDQ or AMDQ credit certificates The person or organisation holding authorised MDQ or AMDQ credit certificates and wishing to transfer that authorised MDQ or AMDQ credit certificate. Long haul transportation of gas via high pressure pipelines. A customer that withdraws gas from a transmission delivery point. A pipeline that is not a distribution pipeline. A person who owns or holds under a lease a transmission pipeline which is being or is to be operated by AEMO. The transmission pipelines or system of transmission pipelines forming part of the gas transmission system as defined under the Gas Industry Act. The difference between metered injected gas supply and metered and allocated gas at delivery points. UAFG comprises gas losses, metering errors, timing, heating value error, allocation error, and other factors. The Underground Gas Storage (UGS) facility at Iona. The interconnection between the EGP and the DTS at Longford, facilitating gas trading at the Longford hub. A price cap, being the maximum, on the market price. Western Transmission System. Transmission pipelines serving Port Campbell to Portland and Western District from Iona. Now integrated into the Gas market and the DTS. 66

70 Appendix 2 References There are a number of reference documents on the AEMO website which provide useful information to assist market participants to gain a good understanding of the workings of the gas market. These documents are listed below. Emergency Gas Load Curtailment and Gas Rationing and Recovery Guidelines Rules and guides Guide to the Victorian Gas Wholesale Market Gas Market Retail Rules Guide to the Victorian Gas Retail Market Technical Guide to the Victorian Gas Retail Market Procedures and Guidelines Gas Scheduling Gas Scheduling Procedures System Security Guidelines Demand Override Methodology Accreditation Procedures Settlements Ancillary Payment Procedure Ancillary Payment Functional Design Data Access Electronic Communication Procedures for Victorian Wholesale Gas Market WebExchanger User Guide MIBB Report Participant Guide Other Documents The Victorian Gas Industry Act Available from the Victorian Legislation and Parliamentary Documents website The National Gas Law Available from the Code Registrar website National Gas Rules Available from the Australian Energy Market Commission website Uplift Payment Procedure Market Suspension Guidelines Uplift Payment Functional Design Compensation Guidelines Uplift Payment Functional Design AMDQ Transfers Procedure AMDQ Transfer Algorithm AMDQ Transfer Guidelines 67

71 Appendix 3 The gas market system SCADA Nodal pressures WEX Actual injections Longford HV Linepack Injection pressure LNG stock level Confirmation of submissions Scheduling intervals definition AMIQ Agency injection hedge nomination/withdrawal Injection & controllable withdrawal bids MP site-specific hourly demand MP non-site-specific hourly demand forecast Nodal hourly demand forecast Operation schedule Actual weather Weather forecast DFS Demand override quantity Scheduling intervals definition Hourly MP demand forecast Weather forecast Actual weather observations Nodal hourly demand forecast TMM Pricing schedule Bids Nodal pressures Nodal hourly demand forecast Supply/demand point constraints Compressor MCE physical ref data & factors BOD injection & withdrawal rates EOD linepack target BoM Scheduled quantities Prices MCE physical ref data & factors Organisational details Heating values MCE MIBB AMIQ limits Meter register Tie-breaking injection rights EDD Settlements supporting data Metering data Meter registration data Zonal hourly heating Agency injection hedge nomination/withdrawal Scheduling intervals definition Operational schedule Pricing schedule Demand override quantity AMIQ Bids MP demand forecast MMS 68

72 Appendix 4 Determination of Authorised Maximum Interval Quantity (AMIQ) A AMDQ Credit CPP <> Longford or B AMDQ CPP = Longford C Determining Uplift Hedge and AMIQ WebExchanger AMIQ profile AMIQ profile Transportation Rights CPP1 Uplift Hedge minimum of aggregate AMDQ CPP = Longford CPP1 Total Uplift Hedge X + CPP1 CPP n Total Uplift Hedge AMIQ 69

73 Appendix 4 Determination of Authorised Maximum Interval Quantity (AMIQ) What 1.3 Transfer AMDQ CC 1.3 Transfer in 1.3 Transfer out TPO Who Market Participant Rule Proc Transfer Procs - Ch Request registration AMDQ CC Spec NA CPP What 1.1 Request Registration 1.2 Allocate to SIP at CPP AMDQ CC SP1 CPP1 Who TPO Rule Proc NA Spec NA What 1.2 Allocate to SIP at CPP Who Market Participant Rule 5.3.5(b) and (ba) Proc NA Spec NA SP n CPP n 1.4 Nominate from SIP to Hub 1.4 Nominate from SIP to TD Site SP1 SP1 AMDQ Credit Nom to Hub Hub X AMDQ Credit Nom to Site Site 1 CPP CPP What 1.4 Nominate from SIP to Hub or Site(s) Who Market Participant Rule AMDQ Credit definition SP 1 Site n CPP SIP 1 CPP SIP 2 CPP Proc Transfer Procs - Ch 4 Spec NA 1.5 Apply diversity factor to site and Aggregate to CPP What 1.5 Apply diversity factor to site and Aggregate to CPP Who VENCorp Rule 3.6.8(ba)(5) Proc Uplift Procs - Ch 4.1 Spec Uplift Funct Des Obtaining AMDQ Credits from AMDQ Credit Certificates AMDQ Credit CPP Curtailment Rights A Tie Breaking Rights CPP 70

74 Appendix 4 Determination of Authorised Maximum Interval Quantity (AMIQ) What 2.1 Transfer AMDQ D Who Market Participant Rule Proc Transfer Procs - Ch 3 Spec NA 2.1 Transfer in 2.1 Transfer out AMDQS le 1 AMDQ D AMDQS le n CPP=Longford CPP=Longford 2.2 Apply diversity factors and aggregate What 2.2 Apply Diversity Factors Who VENCorp Rule 5.6.8(ba)(3)(B) Proc Uplift Procs Spec Uplift Funct Des Authorised MDQ determination What 2.3 Allocate AMDQ V Who VENCorp Rule 5.6.8(ba)(3)(D) Proc Uplift Procs Spec Uplift Funct Des What 2.4 Aggregation of AMDQ 2.3 Allocate in 2.3 Allocate out Who VENCorp Rule 5.6.8(ba)(3) AMDQ V Proc Uplift Procs Spec Uplift Funct Des CPP = Longford X Diversified AMDQ D CPP = Longford Aggregate AMDQ CPP=Longford X AMDQ Hub CPP = Longford 2.1 Transfer in 2.1 Transfer out What 2.1 Transfer AMDQ D Who Market Participant Rule Proc Transfer Procs - Ch 3 Spec NA B Tie Breaking Rights CPP = Longford Curtailment Rights 71

75 Appendix 4 Determination of Authorised Maximum Interval Quantity (AMIQ) WebExchanger (Provider MP) WebExchanger (Recipient MP) SIP1 SIP1 Agency Inj Hedge Nomination Provider MP minimum of Agency Inj Hedge Acceptance Recipient MP Zero CPP CPP Accreditation Valid Agency Inj Hedge Nomination SIP1 SIP1 Recipient MP minimum of Scheduled Inj (AIH Support) Provider MP CPP CPP minimum of Last approved Operating Schedule SIP1 Provider MP CPP Prorate or preference WebExchanger (Provider MP) Inj Hedge Nomination SIP1 Provider MP CPP What 3.2 Injection Hedge Who VENCorp WebExchanger Rule 3.6.8(ba)(5) and (6) Proc Uplift Procs Spec Uplift Funct Des Last Approved Operating Schedule SIP1 SIP1 MP minimum of Inj Hedge Nomination MP CPP CPP Injection Support for Authorised MDQ or AMDQ Credits Tie Breaking Rights Provider MP CPP What 3.1 Agency Injection Hedge Who VENCorp Rule 3.6.8(ba)(5) and (6) Proc Uplift Procs Spec Uplift Funct Des SIP1 Agency Inj Hedge Support Recipient MP CPP SIP1 Recipient MP CPP + Inj Hedge Support SIP1 MP CPP SIP1 MP CPP What 3.3 Total Inj Support at CPP Who VENCorp Rule 3.6.8(ba)(5) and (6) Proc Uplift Procs and 6 Spec Uplift Funct Des and 6 Inj Support C MP CPP 72

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