1. SLIDE 1 VICTORIAN GAS OPERATIONS WINTER OUTLOOK 2014 April 2014

2. SLIDE 2 AGENDA 1:00 - 3:00 Session 1: Introduction AEMO’s Roles and Responsibilities Wallumbilla Gas Supply Hub Winter Weather Outlook DTS Augmentations Emergency Management 3:00 – 3:30 Afternoon tea 3:30 - 5:00 Session 2: Operational Strategy Market Operations Winter Gas Day Case Study 5:00Drinks

3. SLIDE 3 INTRODUCTION - PRESENTED BY MATTHEW CLEMOW

4. SLIDE 4 WINTER STRATEGY Importance of Winter Strategy: Winter demand challenges o High morning and evening peak flows, GPG o System linepack utilisation increases o Weather forecast changes o Market outcomes changing injection locations Analysis of recent transmission augmentations o Impact of changes to the DTS Preparation and training o Industry information o AEMO Gas Operations Consistent and efficient operations Supports a risk based approach to operating the DTS

5. SLIDE 5 WINTER STRATEGY Benefits to industry: Provides participants with: o ‘what we do, and why’ o Annual augmentation and system changes update o Peak day operational strategies Provides confidence and assurance that: o AEMO is prepared and ready to lead through winter o AEMO has developed suitable contingency plans o AEMO will ensure system security is maintained throughout peak demand o AEMO will effectively manage emergencies as required Highlights potential risks Market transparency Building/consolidating relationships

6. SLIDE 6 AEMO’S ROLES AND RESPONSIBILITIES - PRESENTED BY MATTHEW CLEMOW

7. SLIDE 7 ROLES AND RESPONSIBILITIES Gas Real Time Operations (RTO) is responsible for: Safe, Secure and Reliable Operation of the DTS DWGM operations o Scheduling o Transmission including Gas Quality STTM operations DTS project and maintenance coordination Emergency Management Victorian gas planning

8. SLIDE 8 ROLES AND RESPONSIBILITIES Gas RTO contacts: o Matthew Clemow - Senior Manager Gas RTO o Luke Garland - Manager Specialist Operations o Leigh Atkins - Manager Gas System Planning o Jian Ping Lu – Specialist Gas Operations Analyst o Roger Shaw – (Secondment) Senior Manager – Markets Gas RTO structure o Gas Operations Engineers o Specialist Operations Group o Gas System Planning Group

9. SLIDE 9 ROLES AND RESPONSIBILITIES

10. SLIDE 10 ROLES AND RESPONSIBILITIES Other gas contact points within AEMO with Group Manager: o Forecasting and Connections (Gas demand forecasts) – Joe Spurio o Planning (GSOO) – Louis Tirpcou o Market Operations and Performance (Market systems and rules) – Craig Price o Settlements and Prudentials – Chin Chan o Stakeholder Relations (New Participants, Market Training) – Sandra McLaren o Communication and Corporate Affairs (EMS, Media) – Joe Adamo o Retail Markets and Metering (Gas B2B Metering Processes) – Violette Mouchaileh o Business Strategy – Corporate Development (Queensland Gas Supply Hub) – Peter Geers o AEMO Support Hub for general market enquiries

11. © 2014 AEMO. All rights reserved. Presented by Darryl White30 April 2014 Gas Supply Hub Gas RTO Winter Presentation

12. © 2014 AEMO. All rights reserved. Values commodity gas Standardisation of contract terms Low transaction costs Centralised credit and prudential management Forward-dated products Capacity listing service Anonymous real time continuous trade Off market trade settlement through exchange Evolve to meet industry requirements Facilitates east coast trade P12 Benefits of Gas Supply Hub

13. © 2014 AEMO. All rights reserved. East Coast Gas Market P13 Moomba Adelaide STTM Victorian DWGM Sydney STTM Brisbane STTM Wallumbilla Hub Gladstone Carpentaria Pipeline SWQP MSP MAP SEA Gas SWP Culcairn Interconnect EGP RBP Existing Demand Hub Gas Supply Hub QGP Longford Iona Wallumbilla GSH

14. © 2014 AEMO. All rights reserved. P14 Why Wallumbilla? Pipeline Interconnection Gas Fields Wallumbilla Hub Pipeline (with Trading Location) Other transmission pipeline Gas producer Power station Storage Legend Gladstone Moomba Gas Storage Gas Demand Diversity of buyers and sellers Brisbane

15. © 2014 AEMO. All rights reserved. Market Framework AEMO Gas Exchange P15 Pipeline Operator, Producers Gas Transportation Agreements Exchange Agreement Trading Participant Exchange Agreement Gas Supply Hub Trading exchange Settlement and Prudential Delivery Netting Reporting Gas Delivery Nominations Scheduling Metering and allocations Physical Gas Transaction

16. © 2014 AEMO. All rights reserved. Market Framework P16 Voluntary participation Exchange traded contracts for physical delivery Anonymous order submission Standardised contracts Trades matched on price Traders warrant ability to deliver and receipt gas Gas Delivery Participants responsible for gas delivery Centrally settled and cleared Lodge security with AEMO Reallocations

17. © 2014 AEMO. All rights reserved. Gas Trading Exchange P17 Orders for Trading Products Delivery Periods: Balance of Day Day-ahead Daily Weekly Trading Locations: RBP, SWQP & QGP Activity Ticker

18. © 2014 AEMO. All rights reserved. Off Market Trades P18 Gas Supply Hub allows participants to bring a bilateral trade to the market for settlement The facility can be used by parties: that do not have bilateral trading arrangements, prefer the centralised settlement and credit support of the exchange, and For the netting of gas delivery obligations against other exchange transactions

19. © 2014 AEMO. All rights reserved. Delivery Netting Participant only required to deliver their net position Offsetting buy and sell exchange transactions are aggregated together to determine a net delivery position Delivery Variance Market can settle variation between the Delivery Obligation and the Actual Delivered Quantity Other Market Features P19 TradeParticipant AParticipant BParticipant C 115-15 2-1010 3-1010 Total Buy 5ZeroSell 5

20. © 2014 AEMO. All rights reserved. Prudential Monitoring Exposure of Market Participants calculated regularly. AEMO monitors that Exposure < Trading Limit Capacity Listing Service List in bulletin board format consistent with exchange traded commodity screen Facilitate liquidity and movement of gas between nodes and inter-connected markets Other Market Features P20

21. © 2014 AEMO. All rights reserved. Capacity trading standard terms Firm shipper-to-shipper (bare-transfer) pipeline capacity trading Short term forward trades Standardised terms and conditions for trading, operational and settlement processes P21 Other Market Features

22. © 2014 AEMO. All rights reserved. Market Commenced on 20 March 2014 Data as of market close 29 April 2014 P22 GSH Market Activity

23. © 2014 AEMO. All rights reserved. Single trading zone Additional hub locations - Moomba Hub Services Mandated review for SCER in 2015 Storage, Balancing, Compression, Redirection Critical for development of single “Wallumbilla” trading zone Capacity Trading Transaction and settlement services P23 Future Development of GSH

24. © 2014 AEMO. All rights reserved. Credit Risk Management Spot market approach makes collateral requirements relatively high for forward products Margining approach of clearing house is more efficient Forward Products Monthly and Quarterly products Enhance transparency through the establishment of forward curve Participation Financial trading participants would add market liquidity and efficiency P24 Future Development of GSH

25. © 2014 AEMO. All rights reserved. AEMO website - Home > Gas > Market Operations > Gas Supply Hub http://www.aemo.com.au/Gas/Market-Operations/Gas-Supply-Hub P25 Further Information

26. SLIDE 26 WINTER WEATHER OUTLOOK - PRESENTED BY TED WILLIAMS BEAUREAU OF METEOROLOGY

27. SLIDE 27 DTS AUGMENTATION - PRESENTED BY DANIEL TUCCI, APA

28. SLIDE 28 EMERGENCY MANAGEMENT PRESENTED BY MEGAN BRACKSLEY April 2014

29. SLIDE 29 AGENDA 1.What are/is the Emergency Procedures/Protocol 2.What we define as an emergency 3.Responsibility for emergency planning 4.Gas emergency levels 5.Emergency management structures 6.How we identify and respond to emergencies 7.Authority for emergency declarations 8.Communication

30. SLIDE 30 EMERGENCY PROTOCOL

31. SLIDE 31 EMERGENCY PROCEDURES / PROTOCOL The Emergency Procedures (Gas) form part of the Gas Emergency Protocol (the Protocol) The Protocol consists of the following: o Emergency Procedures (Gas) o Gas Load Curtailment and Gas Rationing and Recovery Guidelines o Wholesale Market System Security Procedures

32. SLIDE 32 EMERGENCY PROCEDURES / PROTOCOL Where are they? http://www.aemo.com.au/Gas/Policies-and-Procedures/Gas-Emergency-Procedures

33. SLIDE 33 EMERGENCY DEFINITIONS

34. SLIDE 34 EMERGENCY DEFINITIONS AEMO adopts the definition of emergency contained in NGR Rule 333 Under this rule AEMO has the power to declare an emergency when we reasonably believe there to be a situation which may threaten: o reliability of gas supply; or o system security or the security of a declared distribution system; or o public safety

35. SLIDE 35 EMERGENCY DEFINITIONS …..and AEMO in its absolute discretion considers that the situation is an emergency and declares there to be an emergency; or AEMO declares there to be an emergency at the direction of a government authority authorised to give such directions

36. SLIDE 36 EMERGENCY PLANNING RESPONSIBILITIES

37. SLIDE 37 EMERGENCY PLANNING RESPONSIBILITIES Under Part 19, Division 5, Subdivision 2 of the NGR, Participants have specific obligations with respect to emergency planning These include: o the provision of information to AEMO, including emergency contact details and operational information during an emergency o ensuring staff, and where relevant customers, are aware of the Emergency Protocols o in developing their own safety procedures, ensuring they are consistent with the Emergency Protocol

38. SLIDE 38 GAS EMERGENCY LEVELS

39. SLIDE 39 GAS EMERGENCY LEVELS Level 1 – Site based incident Level 2 – Operational response team Level 3 – Operational and management response teams Level 4 – Impacts multiple industry Participants Level 5 - System wide threat, public safety issue or powers invoked by AEMO, Energy Safe Victoria or the Governor in Council Threat to System Security

40. SLIDE 40 EMERGENCY MANAGEMENT STRUCTURES

41. SLIDE 41 EMERGENCY MANAGEMENT STRUCTURES Victorian Government Emergency Management Structures Gas Industry Specific Structures AEMO Emergency Management Structures Generic Structures of Registered Participants

42. SLIDE 42 GAS INDUSTRY EMERGENCY MANAGEMENT STRUCTURES Gas industry uses existing management structures to support its emergency preparedness and response activities Structures supported by well practiced, agreed and understood communication processes

43. SLIDE 43 GAS INDUSTRY EMERGENCY MANAGEMENT STRUCTURES Energy Industry Response Committee (EIRC) o Chaired by DSDBI o Provides strategic advice to government on the impacts and response to a gas Level 5 emergency o Members of the group are:  the Executive Director Energy and Security, DSDBI (or delegate) as Chair  the Director of Energy Safety, ESV (or delegate)  the Chief Executive Officer of AEMO (or delegate)

44. SLIDE 44 GAS INDUSTRY EMERGENCY MANAGEMENT STRUCTURES Emergency Management Group (GEMG) o Co-ordinates and plans the gas industry’s response to and recovery from an extended gas emergency, normally at a Level 5 o Provides the principal consultation path between the Government and the gas industry

45. SLIDE 45 GAS INDUSTRY EMERGENCY MANAGEMENT STRUCTURES Gas Emergency Management Consultative Forum (GEMCF) o Planning and coordinating forum of industry representatives

46. SLIDE 46 AEMO EMERGENCY MANAGEMENT STRUCTURES AEMO has reviewed its internal emergency management structures Incident Coordination Team (ICT), led by an Incident Coordinator Underpinned by a range of internal policies, procedures and communications platforms

47. SLIDE 47 AEMO EMERGENCY MANAGEMENT STRUCTURES

48. SLIDE 48 GENERIC INDUSTRY EMERGENCY MANAGEMENT STRUCTURES Emergency Response Team or Incident Response Team (Levels 1 and 2) Emergency Management Team (Level 3) Crisis Management Team (Level 4 and 5)

49. SLIDE 49 IDENTIFICATION AND RESPONSE

50. SLIDE 50 IDENTIFICATION AND RESPONSE AEMO maintains its vigilance on the safety and security of supply of Victoria’s gas system through: o operation of a 24/7 Gas Control Centre o maintaining a Gas Duty Manager and Emergency Duty Manager o regular interaction with Registered participants and government departments, including emergency services o gas and weather forecasting processes

51. SLIDE 51 IDENTIFICATION AND RESPONSE Keep Registered participants informed about the nature, extent and expected duration of emergencies, including updates of the emergency status as required through: o System Wide Notices (SWN) o Victorian Energy Emergency Communications Protocol (VEECP) Expected that Registered participants will: o Advise all relevant officers, staff, and where required, its customers about the existence of and nature of the emergency o Adhere to the agreed industry processes for the identification, and notification of foreseeable and existing emergencies.

52. SLIDE 52 IDENTIFICATION AND RESPONSE In the event that a likely or actual emergency is identified by AEMO, Registered participant, or government department, the following steps occur: o the identifying organisation notifies AEMO of any event or situation it becomes aware of o AEMO activates the VEECP o when an emergency arises, AEMO notifies ESV and advises Registered participants through a SWN o where emergency powers are invoked, each Registered participant complies with all emergency directions given by AEMO, ESV or government

53. SLIDE 53 AUTHORITY TO DECLARE EMERGENCIES

54. SLIDE 54 AUTHORITY TO DECLARE EMERGENCIES AEMO o AEMO may declare a Level 5 Emergency or a Threat to System Security o AEMO derives its authority to declare an emergency and issue directions under the NGR and Section 91BC of the National Gas (South Australia) Act 2008 Energy Safe Victoria o The Director of Energy Safety, ESV may also issue a direction under Section 107 of the Gas Safety Act 1997 Governor in Council o The Governor in Council may declare an emergency under Part 9 of the Gas Industry Act 2001, on advice from EIRC

55. SLIDE 55 THREAT TO SYSTEM SECURITY If AEMO believes declaring a Threat to System Security is necessary, via a SWN, we will notify Registered participants on: o Nature and magnitude of the Threat to System Security o Whether AEMO will need to intervene in the market o The system withdrawal zones in which the Threat to System Security is likely to be located Once the Threat to System Security has subsided, AEMO will inform Registered participants through a SWN

56. SLIDE 56 COMMUNICATION

57. SLIDE 57 COMMUNICATION Communication systems and processes during emergencies are critical AEMO and industry use agreed processes: o Those required under the rules (Market Notices) o Victorian Energy Emergency Communication Protocol o Single Industry Spokesperson

58. SLIDE 58 COMMUNICATION AEMO uses Market Notices to keep Registered participants informed on changes that may impact the gas market This includes the use of System Wide Notices (SWN) to Registered participants during an emergency

59. SLIDE 59 VICTORIAN ENERGY EMERGENCY COMMUNICATIONS PROTOCOL (VEECP) Developed by AEMO and Victorian gas and electricity industry stakeholders Ensures timely and accurate advice and information is disseminated in a coordinated manner Complements existing AEMO, industry and government emergency policies and procedures Operates across the range of emergency levels 1 to 5, including a Threat to System Security

60. SLIDE 60 SINGLE INDUSTRY SPOKESPERSON (SIS) – MEDIA MANAGEMENT Typically Victorian gas industry Registered participants would manage media relations for emergency Levels 1 to 4 AEMO may communicate through the media for Levels 4 and 5, where the Single Industry Spokesperson (SIS) is invoked SIS ensure a consistent message to the public during a gas emergency

61. SLIDE 61 QUESTIONS?

62. SLIDE 62 Coming up in Session 2 Operational Strategy - presented by Hayden Butler Market Operation - presented by Daniel Lavis Winter 2013 Case Study - presented by Hayden Butler

63. SLIDE 63 TRANSMISSION OPERATION - PRESENTED BY HAYDEN BUTLER

64. SLIDE 64 TRANSMISSION OPERATION Operations Overview Declared Transmission System (DTS) Facility Upgrades Demand and Supply Outlook Operational Strategies Longford to Melbourne Pipeline South West Pipeline, including Brooklyn Operations Northern System, including the NSW Interconnect Managing Peak Demand Days

65. SLIDE 65 DECLARED TRANSMISSION SYSTEM Melbourne Echuca Gooding CS Wollert CS Brooklyn CS Sunbury Ballarat Maryborough BendigoEuroa CS Springhurst CS Koonoomoo Wodonga Brooklyn - Lara Pipeline Geelong Portland Longford Culcairn Vic Hub Iona SEAGas Otway Mortlake Bass Gas LNG Iona CS Wandong Pipeline Transportation Capacity TJ / day Export Capacity TJ / day Longford Pipeline1,030- South West Pipeline367*129 Northern Pipeline120 42 - 86 57 – 86 Dandenong Lara The Maximum SWP Injection is 384 TJ/day due to demand in the Western Transmission System Approx 70% of winter system demand Plumpton

66. SLIDE 66 FACILITY UPGRADES What / where Estimated Completion Operations impact Northern Zone Northern System Looping: First Stage Looping 27.8 km north of Wollert to Wandong June 2014 Increased Culcairn export capacity from 42 TJ/day to 57 TJ/day Northern System Looping: Stages 2 & 3 May 2015 Increased Culcairn export capacity to 113 TJ/day South West Pipeline Winchelsea Compressor Station: A new uni-directional Taurus 60 compressor January 2015Increased SWP transportation capacity from 367 TJ/day for winter 2014; to 429 TJ/day for 2015

67. SLIDE 67 DEMAND AND SUPPLY OUTLOOK - DEFINITION System Demand is the aggregate Tariff V and Tariff D consumption o Excludes Gas Powered Generation demand In this presentation, Total Demand in the DTS is the aggregate of: o System Demand o Gas Powered Generation demand

68. SLIDE 68 DEMAND-SUPPLY OUTLOOK - DEMAND System Demand The winter 2014 peak day system demand forecast is similar to forecast demand during the previous winter. (Data from VGPR) Actual System Demand Year1 in 2 peak day1 in 20 peak day Winter 2014 Forecast System Demand (TJ/Day)1,1551,277 Winter 2014 Forecast (EDD)14.216.5 Winter 2013 Forecast System Demand (TJ/Day)1,1491,270 Winter 2013 Forecast (EDD)14.216.5 YearEDDHighest System Demand Day 201311.91,082 201212.11,092 201114.81,145 201013.91,182 200716.81,255 (Highest ever)

69. SLIDE 69 DEMAND-SUPPLY OUTLOOK - DEMAND Winter System Demand Profiles Peaks approx. equal magnitude Evening peak longer duration Daytime minimum 50-55% of peak Overnight minimum 30-35% of peak

70. SLIDE 70 DEMAND SUPPLY OUTLOOK – GPG Gas Powered Generation (GPG) Outlook Low average daily GPG demand for the past 5 years (May to September) ~ 23% lower in 2013 than the average daily GPG demand for the same period in 2012 Winter 2014 average daily demand expected to be similar to 2012 & 2013 Peak daily GPG 2013 Unplanned outage Yallourn Power Station

71. SLIDE 71 DEMAND SUPPLY OUTLOOK – SUPPLY Maximum supply capacities from each region: Supply Source Estimated Available Supply (TJ/day) Maximum Injection Capacity (TJ/day) Esso Longford 961 1,030 VicHub BassGas55 Iona UGS 550384 SEAGas Otway Mortlake Culcairn60120 Total (excluding LNG) 1,349 1 NOTE: These transportation capacities are only achievable under ideal conditions and if scheduled from the beginning of the day. 1 As pipelines approach their capacities, a back off effect occurs due to network topology and net demand location, resulting in a net reduction of system capacity.

72. SLIDE 72 OPERATIONAL STRATEGIES Longford to Melbourne Pipeline South West Pipeline, including Brooklyn Operations Northern System, including the NSW Interconnect Managing Peak Demand Days

73. SLIDE 73 OPERATIONAL STRATEGIES Operational Strategy Key Goal Longford to Melbourne Pipeline Avoid Longford high pressure event, and ensure minimum DCG pressure South West Pipeline Strategy Managing high injections in SWP to support winter demand Northern Pipeline Strategy Supporting withdrawals to NSW via Culcairn Managing Peak Demand Days Managing surprise demand, and reducing likelihood of curtailment

74. SLIDE 74 LONGFORD PIPELINE STRATEGY Gooding CS Longford Vic Hub Bass Gas LNG Dandenong (DCG) Wollert CS When there is forecasted high Longford pressure: Balance system linepack using Wollert CS and/or Brooklyn facilities Gooding compression to reduce pressures at Longford Communicate strategy with Longford When DCG forecast pressure is low: 1.Utilise all available linepack 2.Inject firm rate LNG 3.Reduce Wollert compression 4.Inject non-firm LNG

75. SLIDE 75 SOUTH WEST PIPELINE STRATEGY SWP = Iona to Lara Pipeline + Brooklyn to Lara Pipeline South West zone all supplied from SWP Sunbury demand supplied from the BLP via Plumpton PRS Ballarat demand supplied from BLP via Brooklyn Ballan PRS Brooklyn compression to Ballarat only required on very high demand days (Not required winter 2013) Without suitable Iona injections, Brooklyn compression is required to support system demand Sunbury Ballarat Brooklyn - Lara Pipeline Geelong Portland Iona SEAGas Otway Mortlake Iona CS Lara Plumpton Brooklyn CS SWP linepack adjusted by gas flow through BCP City Gate

76. SLIDE 76 SOUTH WEST PIPELINE STRATEGY The transportation capacity of the SWP is demand dependant Historical schedule outcomes result in net injections at Iona well below capacity, except on very high system demand days SWP Transportation Capacity

77. SLIDE 77 SOUTH WEST PIPELINE STRATEGY SWP = Iona to Lara Pipeline + Brooklyn to Lara Pipeline The change in injection rate can be large between scheduling horizons / gas days Operational challenge to manage SWP linepack BLP CG Inlet minimum pressure limited to 4,500 kPa Operational pressure at Iona varies depending on the injection rate at Iona Market Participant forecast accuracy affects intra-day swing The injections into the SWP are expected to be close to the transportation capacity for high demand days.

78. SLIDE 78 SOUTH WEST PIPELINE STRATEGY The usable linepack in SWP diminishes when Iona injection rate approaches the SWP design capacity The usable linepack is a function of flow rate Injection rate  Usable linepack  4,000 5,000 6,000 7,000 8,000 9,000 10,000 Pressure (kPa) 01020 IonaBrooklyn

79. SLIDE 79 SOUTH WEST PIPELINE STRATEGY To achieve the EoD linepack target for various Iona injection rates, Iona pressure must increase/decrease accordingly Example: based on a flat injection rate of 280 TJ/day, the operational EoD pressure target is ~ 8,500 kPa Iona pressure Usable Linepack

80. SLIDE 80 NORTHERN PIPELINE STRATEGY The trend of increasing withdrawals for the past two winters at Culcairn is expected to be seen again this winter 2014. The first stage of the Northern Looping Project (Wollert to Wandong) is expected to be in service June 2014.

81. SLIDE 81 NORTHERN PIPELINE STRATEGY Northern pipeline transportation capacity o Culcairn withdrawal capacity is demand dependant o Northern looping will increase export capacity

82. SLIDE 82 NORTHERN PIPELINE STRATEGY Culcairn Withdrawal Increased exports to NSW in 2013 compared to the same time in 2012 AEMO is prepared for higher exports during winter 2014 if this trend continues Northern compression will be operated throughout the gas day as required to support Culcairn withdrawals

83. SLIDE 83 NORTHERN PIPELINE STRATEGY 1.Wollert CS: o Supporting northern system demand o Supporting Culcairn withdrawals o Movement of linepack into Northern zone to aid in reducing Longford pressure 2.Springhurst CS: o When required, provides high operational pressure at Culcairn to support withdrawal 3.Euroa CS: o Provides a higher suction pressure to Springhurst CS to transport large exports to NSW when required o Euroa compressor station increases export transportation capacity by approximately 20 TJ/day when run in conjunction with Wollert and Springhurst compression

84. SLIDE 84 PIPELINE STRATEGY SUMMARY Manage individual pipelines to balance system linepack. Consider impact of demand forecast uncertainty. Allow for market driven variation in injection schedules. Melbourne Echuca Gooding CS Wollert CS Brooklyn CS Sunbury Ballarat Maryborough BendigoEuroa CS Springhurst CS Koonoomoo Wodonga Brooklyn - Lara Pipeline Geelong Portland Longford Culcairn Vic Hub Iona SEAGas Otway Mortlake Bass Gas LNG Iona CS Wandong Dandenong Lara Approx 70% of winter system demand Plumpton

85. SLIDE 85 MANAGING PEAK DEMAND DAYS Challenges: Forecast uncertainties Linepack management Strategies: Utilising all available linepack Longford injection profiling Prioritisation of peak shaving injections Early Market notifications

86. SLIDE 86 MANAGING PEAK DEMAND DAYS 6am10am2pm6pm10pm EDD11.411.813.413.513.7 System Forecast9529701,0441,0461,053 GPG Forecast65 6064 Total1,0181,0351,1051,1101,117 Under-forecast by 100 TJ at the BoD (approximately 4 TJ/hr) Lost about 29 TJ linepack prior to the evening peak (6pm) Equivalent to 5 hour firm-rate LNG vapourisation of 100 tonnes/hour (5.5 TJ/hr) 4 TJ/hr Forecast uncertainties are due to: Unexpected weather changes: System Demand increases by ~3 TJ/hr for every degree drop in temperature during the evening peak Sudden variation in forecast GPG demand : Under-forecasting example

87. SLIDE 87 MANAGING PEAK DEMAND DAYS Peak shaving gas Perfect Forecast Actual Forecast Injection rate increases Linepack is depleted throughout afternoon More LNG required

88. SLIDE 88 MANAGING PEAK DEMAND DAYS Supplying Peak Demand: 1.Utilising all available linepack prior to scheduling peak shaving gas injections 2.Injecting LNG up to 100 tonne/hour (5.5 TJ/Hr) to support peak demand 3.Reduce compression at Wollert CS before vaporising non-firm LNG Intra-day Longford Injection Profiling: o Only applied when AEMO 4pm, Day+1; Total Demand Forecast (System Demand + GPG) ≥ 1,150 TJ/Day Early Warning Notification: o Providing early warning to the market when there is increased potential for curtailment

89. SLIDE 89 SUMMARY Operational strategies Longford Pipeline South West Pipeline Northern zone Managing Peak Demand Days Conclusion Similar expected conditions to winter 2013 Supply-Demand balance similar to previous winter AEMO operating strategies will accommodate system changes AEMO is confident that the operational strategies are suitable and will result in effective operations for winter 2014.

90. SLIDE 90 QUESTIONS?

91. SLIDE 91 MARKET OPERATION - PRESENTED BY DANIEL LAVIS

92. SLIDE 92 Constraints Overview SDPC/DFPC o Process for application of o Notification and required information NFTC SSC Managing Peak Demand Injection Profiling Culcairn Scheduling Methodology LNG (Operational Response and Market scheduled) Market Communications Market Notices Confirmation process Review Cumulative Price Threshold adjustment Demand Forecast Override Methodology MARKET OPERATION

93. SLIDE 93 CONSTRAINTS Overview SDPC/DFPC o Process for application of o Notification and required information NFTC SSC

94. SLIDE 94 CONSTRAINTS OVERVIEW Supply Demand Point Constraint (SDPC) Directional Flow Point Constraint (DFPC) Net Flow Transportation Constraint (NFTC) Supply Source Constraint (SSC)

95. SLIDE 95 CONSTRAINTS (SDPC/DFPC) Reflects actual physical injection/withdrawal capability Triggers: Facility operator initiated: temporary production slow down Interconnected pipeline operational pressure constraint planned maintenance plant/facility trip AEMO initiated: transmission system capability gas quality consideration emergency requirement

96. SLIDE 96 CONSTRAINTS (SDPC/DFPC) Facility Operator Notification Process: Advised to AEMO by facility operator Clear and accurate information is crucial. AEMO will attempt to clarify any uncertainties If time permits, the constraint will be applied from next applicable scheduling horizon For maintenance, constraint to be applied Partial Day – MHQ set to zero for duration of outage Full Day – AEMO expects Market Participants to bid in good faith, and reflect plant outages within their bidding

97. SLIDE 97 CONSTRAINTS (SDPC/DFPC) Required constraint information: Applicable MIRN/MIRNs Description and reason Start and end time Hourly flow (profile) limitation and/or daily constraint For a DFPC, specify either net injection or withdrawal Note: Financial flow at a paired meters will be supported only when a facility is in operation

98. SLIDE 98 CONSTRAINTS (SDPC/DFPC)

99. SLIDE 99 CONSTRAINTS (SDPC/DFPC) AEMO declares the threat, and runs ad-hoc schedule with constraint. Threat to System Security? Immediate Threat? Clear information? Monitor system & attempt to clarify with facility operator Apply constraint in next scheduling horizon(s). Quality of information is crucial. AEMO requires timely details of the event to be confirmed prior to applying constraint over the next horizon(s). Send out SWN Facility operator Notifies AEMO of constraint request Assessment of Constraints: Apply constraint in next scheduling horizon(s).

100. SLIDE 100 NET FLOW TRANSPORTATION CONSTRAINT (NFTC) Reflects the total net injection/withdrawal capacity of a pipeline such as the SWP Application: Applies across all injection and withdrawal points (three or more) at the same location Purpose: Scheduled net injection or withdrawal that reflects the physically capability Ensure correct tie-breaking to Market Participants across all injection/withdrawal points covered by the NFTC grouping

101. SLIDE 101 NFTC SCHEDULING METHODOLOGY NFTC applied to combined injections at Iona AEMO will schedule net injections at Iona node; (Iona, SEAGAS, Mortlake & Otway meters) up to VGPR capacity Capacity is applied on hourly timescale Market will be notified of NFTC application NFTC Applied

102. SLIDE 102 SUPPLY SOURCE CONSTRAINTS (SSC) Purpose to reflect gas producer injection capability, where: Multiple supply sources exist at a single injection point Facility operator will cease to inject gas (from one of the supply sources) into the DTS, if the supply source fails to inject gas MP must have registered to utilise this constraint via accreditation application Current status This feature was implemented prior to winter 2011* This constraint has not been applied to date.

103. SLIDE 103 MANAGING PEAK DEMAND - Longford Injection Profiling - Culcairn Scheduling Methodology - LNG scheduling

104. SLIDE 104 LONGFORD INJECTION PROFILING System security benefit: Increases system security margins on peak days by conserving or increasing system usable linepack prior to the evening peak Ultimately reduces likelihood of curtailment by reserving LNG peak shaving capacity Market impact: Profiling injection will result in no impact on either imbalance or deviation payments AEMO expects this strategy will be utilised infrequently

105. SLIDE 105 LONGFORD INJECTION PROFILING The process: Triggered if AEMO’s Total demand forecast at the 4pm Day+1 schedule, exceeds 1,150 TJ/day Performed in consultation with both ESSO and Jemena. AEMO will apply a Minimum Hourly Quantity (MinHQ) through an SDPC increasing the injection rate by up to 2 TJ/hr for the first 14 hours

106. SLIDE 106 LONGFORD INJECTION PROFILING Scheduled Longford Injection Profile:

107. SLIDE 107 CULCAIRN SCHEDULING METHODOLOGY Scheduling process will be the same as last year Normal operating conditions o VGPR capacity – increased for Winter 2014 o Scheduling out-of-merit-order LNG up to firm rate Abnormal operational conditions

108. SLIDE 108 CULCAIRN SCHEDULING METHODOLOGY Under normal operational conditions, AEMO will schedule Culcairn withdrawal up to VGPR capacity Capacity will be applied on an hourly timescale Capacity limited by constraint within NSW if applicable Market will be notified of constraint (SDPC /DFPC) application

109. SLIDE 109 CULCAIRN SCHEDULING METHODOLOGY Scheduling out-of-merit-order LNG up to firm rate up to 100 tonne/hour (5.5 TJ/hour) of LNG will be used prior to and during the evening peak if metropolitan pressures are forecast to fall below minimum Wollert compression will then be reduced or shutdown to maintain metropolitan pressures above minimum

110. SLIDE 110 CULCAIRN SCHEDULING METHODOLOGY An Abnormal condition is when the system is not capable of transporting the capacity defined in the VGPR Abnormal conditions may result through: o Facility failure o > 100 tonnes/hour (5.5 TJ/hour) of LNG vaporisation o A threat to system security o An Emergency situation If an abnormal condition exists AEMO will: o determine the withdrawal capacity and apply a constraint o advise APA Culcairn operations of the revised capacity o notify the market via a system wide notice (SWN)

111. SLIDE 111 LNG SCHEDULING Operational Response: Minimum Hourly Quantity (MinHQ) is used within an SDPC to schedule LNG into Operating Schedule for peak shaving as required Advance notice is provided to APA when increased probability of LNG identified Scheduling to occur with consideration for LNG plant operating limitations Market Response (merit order injection): Injection scheduled flat across remainder of gas day Note: AEMO may profile injections for System Security reasons When hourly scheduled injections < minimum plant flow This is a commercial decision for MPs / APA regarding how or if to flow P111

112. SLIDE 112 LNG SCHEDULING The quantity and timing of LNG required for peak shaving purpose is determined by AEMO through use of the following operational tools: Market Clearing Engine (MCE) Mass Balance Gregg Model Rate of Pressure Decline at DCG inlet Unlike other injection sources, AEMO provides LNG scheduling instructions directly to APA Dandenong

113. SLIDE 113 LNG SCHEDULING LNG Injection Profile: Scheduling: First hour ≤ 5 TJ/hour Last hour ≤ 5 TJ/hour Extends across multiple horizons Can be changed at next horizon Firm5.5 TJ/Hr (100t/hr) Non-Firm 8.2 TJ/Hr (150t/hr) Max 9.9 TJ/Hr (180t/hr)

114. SLIDE 114 MARKET COMMUNICATIONS - Market Notifications - Schedule confirmation process

115. SLIDE 115 MARKET COMMUNICATIONS Market Notices: SWN(SMS/Email), will be sent for: o SDPC / DFPC / NFTC constraints applied o Low linepack reserve notice o Large increase of EDD o Running an ad hoc schedule o Schedule confirmation discrepancies Via Email: o Intra Day Demand / Supply Shortfall Likelihood o Daily Demand/Supply forecast

116. SLIDE 116 MARKET NOTIFICATION – LOW LINEPACK RESERVE Example Low Linepack SWN Red: Priority RED – Extreme Low Linepack Reserve – LNG requested above 100 t/hr at XX:XX hours Priority RED – XXX t/hour of requested LNG cannot be supplied, XXX t/hr available for supply at XX:XX hours Amber: Priority AMBER – Low Linepack Reserve – LNG requested up to 100 t/hr at XX:XX hours Green: Priority GREEN – Supply Reserves Manageable – No LNG requested

117. SLIDE 117 MARKET NOTIFICATION – EDD RAPID INCREASE SWN is triggered if the EDD is above 14.0 °C and increases by 1.0 °C between scheduling intervals Example SWN/SMS EDD increase alert, since the last schedule the EDD has increased from XX to XX

118. SLIDE 118 MARKET NOTIFICATION – AD HOC SCHEDULE The ad-hoc scheduling process is triggered when a supply/demand imbalance is identified that cannot wait until the next scheduling window AEMO will declare a threat to system security prior to publishing an ad-hoc schedule Example SWN/SMS Be advised that there is a Threat to System Security due to or.

119. SLIDE 119 MARKET NOTIFICATION – EMAIL SUPPLY SHORTFALL Demand/Supply Shortfall Likelihood Notification, triggered for current day when Total demand forecast > 1,150 TJ/d Example Email Sent to: Supply_Demand (CRM) Available via request, contact AEMOHelpdesk@aemo.com.au

120. SLIDE 120 MARKET NOTIFICATION – EMAIL DEMAND/SUPPLY FORECAST

121. SLIDE 121 CONFIRMATION PROCESS Facility Operator AEMO MP 1 MP 2 MP 3 Market Participants Market Participants Nominations AEMO Scheduling Instruction Confirmation Process Bids, Demand Forecasts etc Nomination vs. Schedule

122. SLIDE 122 CONFIRMATION PROCESS Facility Operator does not confirm AEMO’s scheduled quantity For the Current Day, if the difference >5TJ: o AEMO will contact the F.O seeking clarification o If the F.O cannot vary their injections and the ∆ is considered material (>20TJ), then AEMO will; o Publish SWN, seeking update in nominations for a specific injection point Example SWN/SMS MPs please confirm the noms for gas day dd/mm/yy scheduled at [meter]. The confirmation process identified significant difference from the schedule

123. SLIDE 123 CONFIRMATION PROCESS At the next scheduling horizon (or earlier if required), AEMO will; Publish another SWN requesting MPs to advise AEMO of their: Scheduled quantities from the MIBB Nominations to the facility Reason for any discrepancy If the discrepancy cannot be resolved and AEMO believes that the situation impact system security, AEMO may take whatever action is necessary to rectify the problem.

124. SLIDE 124 CUMULATIVE PRICE THRESHOLD

125. SLIDE 125 CUMULATIVE PRICE THRESHOLD The Cumulative price is the sum of the market price over the last 35 schedules, including the current schedule. AEMO identified the need to review the Cumulative Price Threshold to better manage the risks to the market. On 1 st April 2014, following consultation, CPT was adjusted from 3,700 to $1,800 /GJ

126. SLIDE 126 DEMAND FORECAST OVERRIDE METHODOLOGY

127. SLIDE 127 DEMAND FORECAST OVERRIDE METHODOLOGY Changed in July 2013. New thresholds, factors & weather condition inputs into override Profile shape of Total Demand (incl. GPG), taken into account Override only to prevent threats to system security Reduction of unnecessary overrides Old MethodologyNew Methodology 2012 2013 (Until July) July 2013 to Present Overrides Up 981 Overrides Down 112864 Total Overrides 121945

128. SLIDE 128 SUMMARY Applications of Constraints: o SDPC, DFPC, NFTC and SSC Scheduling processes for managing Peak Demand days o Longford Injection Profiling o LNG dispatch o Supporting Culcairn exports Market communication process Cumulative price threshold Demand Forecast Override Methodology

129. SLIDE 129 QUESTIONS?

130. SLIDE 130 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE

131. SLIDE 131 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE This case study will show: o AEMO’s peak demand day operational strategy o Impact of forecast uncertainty o LNG injected for peak shaving o Market communications

132. SLIDE 132 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE Beginning of Day (BoD) Schedule InputsDaily Quantity BoD Linepack (Target 380 TJ) 372 TJ System Demand Forecast Market Participant1,034 TJ AEMO999 TJ Difference35 TJ GPG Forecast(Market)30 TJ Total Demand ForecastMarket Participant1,064 TJ 6AM Schedule Injections1,129 TJ Controllable Withdrawals58 TJ Net Injections1,073 TJ

133. SLIDE 133 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE 6am Scheduling Horizon

134. SLIDE 134 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE 10am Scheduling Horizon Prior to 2pm Scheduling Horizon

135. SLIDE 135 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE 2pm Scheduling Horizon

136. SLIDE 136 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE MARKET NOTICES: SUMMARY: o Under-forecast GPG Resulting in linepack shortfall o At 2pm Schedule: 20 TJ Peak Shaving LNG  (2.5 TJ per hour, commencing at 3pm) o At 6pm Schedule: 20 TJ Peak Shaving LNG Maintained  (Continued at 2.5 TJ per hour rate) TimeSWN 2:02pmLinepack reserve condition amber - LNG scheduled at less than 100 t/hr from 15:00 hrs 2:18pmSDPC applied at 30000101PC for gas day 21/06/13 due to operational requirements 10:06pmSDPC removed at 30000101PC for gas day 21/06/13 due to operational requirements 10:10pmLinepack reserve condition GREEN - Supply Reserves Manageable. No operational response LNG requested

137. SLIDE 137 CASE STUDY WINTER 2013: GAS DAY 21 ST JUNE Operational Strategies + Effective Procedures = Winter Preparedness

138. SLIDE 138 QUESTIONS?