WINTER 2017 VICTORIAN GAS OPERATIONS OUTLOOK

Transcription

1 WINTER 2017 VICTORIAN GAS OPERATIONS OUTLOOK 10 May 2017 SLIDE 1

2 AGENDA 10:30-11:20 Session 1 Future Gas Supply and Demand Introduction (AEMO) National Gas Forecasting Report (AEMO) Gas Statement of Opportunities (AEMO) Victorian Gas Planning Report (AEMO) 11:20-12:00 Session 2 Transmission System next 5 years APA s VTS Regulatory Proposal (APA) AER s Regulatory Determination (AER) 12:00-1:00 Lunch SLIDE 2

3 AGENDA 1:00-3:00 Session 3 Winter Operations 2016 Winter Review (AEMO) 2017 Weather Outlook (Weatherzone) 2017 APA Augmentations (APA) Transmission Operations (AEMO) 3:00-3:30 Afternoon Tea 3:30-5:00 Session 4 Market and Emergency Operations Abnormal Market Operations (AEMO) Emergency Operations (AEMO) Summary of Key Messages (AEMO) 5:00-6:00 Networking SLIDE 3

4 INTRODUCTION Presented by Matthew Clemow Senior Manager, AEMO Gas Real Time Operations SLIDE 4

5 WINTER STRATEGY - IMPORTANCE Winter demand challenges o High morning and evening peak flows o System linepack utilisation increases o Limited support for Gas Powered Generation (GPG) o Weather forecast changes o Market outcomes change injection locations Consistent and efficient operations o Predictable outcomes for participants Manage DTS operational risks o Per the AEMO Gas Safety Case SLIDE 5

6 WINTER STRATEGY - IMPLEMENTATION Analysis of transmission system changes o Supply source changes, e.g. TGP o Demand changes, e.g. forecast increase in GPG o Pipeline changes, e.g. further VNI expansion works o How AEMO will manage these changes Preparation and Training o Information for Industry Participants Winter Strategy Presentation Winter Strategy Paper o AEMO Gas Operations Engineers Pre-winter training SLIDE 6

7 WINTER STRATEGY BENEFITS Provides participants with information about: o System changes o AEMO s operations and scheduling o Highlights any potential risks Increases transparency Opportunity to ask questions Provides confidence and assurance that AEMO is prepared and ready to manage winter operations SLIDE 7

8 AEMO S ROLES AND RESPONSIBILITIES SLIDE 8

9 DWGM - DTS Overview SLIDE 9

10 AEMO OPERATION OF THE DECLARED TRANSMISSION SYSTEM Safe, Secure and Reliable Operation of the DTS Maintain System Security o Manage pipeline gas flows using the AEMO Gas SCADA o Operating strategies to maintain pipeline pressures o Adapt based on expected scheduled injections o Engineering modelling tools including Gregg Model o Threats to System Security Emergency Management o Assess, Respond and Communicate Monitor and manage Gas Quality o SCADA Communications with Gas Facilities o Gas Quality Procedures and Management Plans Gas metering data collection via AEMO Gas SCADA o Facilities, Larger users and GPG, Distribution offtakes SLIDE 10

11 AEMO OPERATING ARRANGEMENTS FOR THE APA OWNED SYSTEM Operate the DTS per the Service Envelope Agreement (SEA) o Agreed operations and reliability standards o Incident review and continuous improvement AEMO management of outages to maintain gas supply o Releases APA Assets for Maintenance o Victorian Gas Maintenance Coordination process DTS project review and pipeline capacity modelling o Model pipelines to agree transportation capacities with APA o Operability including SEA requirements New DTS Connections o Distribution offtakes o Facilities including Operating Agreements SLIDE 11

12 MARKET OPERATIONS Gas Demand Forecasting o Market participant forecasts adjusted against actual flow o Demand Override Methodology o Direct Call to Weather Forecasting Service Monitoring GPG o NEM Pre-dispatch Scheduling Pipeline Injections and Withdrawals o Market Clearing Engine generates schedules o Pricing Schedule Infinite Tank Model with no DTS pipeline capacity constraints o Operating Schedule Actual scheduled flows accounting for DTS capacity Peak Shaving LNG to support system pressure SLIDE 12

13 HOW THE VICTORIAN DTS IS DIFFERENT The Victorian DTS is complex and different o o Three main transmission pipelines two are bi-directional with interactions between these. Pipeline pressure and linepack variations are significant Supply sources and pipeline linepack o o DTS main supply sources Longford and the Port Campbell facilities are approx. 200 km from to Melbourne Sydney and Adelaide are each supplied by two pipelines approx. 1,000 km long more linepack than the DTS Victoria has the coldest winter of the mainland states and the highest residential gas demand o o o Demand varies substantially with temperature Weather forecast inaccuracies create demand uncertainty Gas Powered Generation impact on linepack SLIDE 13

14 SHORT TERM TRADING MARKET (STTM) AEMO is the market operator not the system operator o o o Pipeline owners continue to operate their assets AEMO is not responsible for system security STTM facility operators notify AEMO of supply issues via the Contingency Gas Hotline AEMO manages the Contingency Gas process Assessment Conferences Industry Conferences Contingency Gas determination Contingency Gas scheduling SLIDE 14

15 AEMO GAS CONTROL CENTRE Located in Melbourne Two staff, 24/7, 12 hour shifts o o Operate the Victorian DTS Schedule the Victorian DWGM Regular interaction with Facility Operators, APA, and Market Participants o o o o o o Maintenance Coordination and Facility Release processes Notification to APA of DTS equipment issues Application of DTS and Facility Constraints (e.g. NFTC, SDPC) Gas Quality monitoring and response Gas Powered Generation monitoring and forecast variations STTM Contingency Gas Hotline SLIDE 15

16 AEMO GAS REAL TIME OPERATIONS STRUCTURE Matthew Clemow Senior Manager Gas Real Time Operations Mark Pollock Manager Gas Real Time Operations Luke Garland Manager Gas System Operations Gas Operations Engineers Scheduling Desk Transmission Desk Gas Safety Case Emergency Response Gas System Operations Manual Transmission Operation Guide Short Term Trading Market Contingency Gas Escalation Gas Operations Analysts Market Operations and Systems (DWGM and STTM) Disaster Recovery Emergency Preparedness Competency Based Learning Transmission Engineers Service Envelope Agreement Capacity Modelling VGPR Maintenance Planning New Connections SCADA Metering Gas Quality SLIDE 16

17 QUESTIONS? SLIDE 17

18 2016 NATIONAL GAS FORECASTING REPORT (NGFR) OUTCOMES May 2017 PRESENTED BY GREGORY STAIB SLIDE 18

19 AGENDA About the 2016 National Gas Forecasting Report (NGFR) Summary points and forecasts o Total consumption, all regions and VIC Next steps and questions SLIDE 19

20 ABOUT THE 2016 NGFR SLIDE 20

21 ABOUT THE 2016 NGFR SLIDE 21

22 Petajoules (PJ) SOUTH-EAST AND EASTERN AUSTRALIA: ANNUAL CONSUMPTION SCENARIOS (INC. LNG) 3,000 2,500 2,000 1,500 1, Calendar Year Ending High Low Medium Strong Weak Neutral Actual Historical SLIDE 22

23 Petajoules (PJ) SOUTH-EAST AND EASTERN AUSTRALIA: ANNUAL CONSUMPTION SCENARIOS (EXCL. LNG) 1, Calendar Year Ending High Low Medium Strong Weak Neutral Actual Historical SLIDE 23

24 Petajoules (PJ) SOUTH-EAST AND EASTERN AUSTRALIA: ANNUAL CONSUMPTION 2,500 2,000 Historical Forecast 1,500 1, Calendar Year Ending Res. & Comm. Industrial GPG LNG 2015 including LNG 2015 excluding LNG SLIDE 24

25 FORECASTS FOR VICTORIA 250 Historical Forecast 200 Petajoules (PJ) Calendar Year Ending VIC 2016 Residential & Commercial VIC 2016 Gas Powered Generation VIC 2016 Industrial VIC 2015 Medium SLIDE 25

26 TRANSFORMING FORECASTING Transformation program aims to: Integrate gas and electricity forecasting. Integrate supply and demand modelling. Make more timely information available as significant industry changes occur. SLIDE 26

27 QUESTIONS Thank you. For more information on these AEMO forecasting reports, please contact: SLIDE 27

28 2017 GAS STATEMENT OF OPPORTUNITIES May 2017 PRESENTED BY AEMO RACHAEL SAW CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 28

29 THE 2017 GSOO The 2017 GSOO provides industry participants and policymakers with transparent information to support: Decision-making on the supply of gas in Australia s long-term interests Adequacy of gas infrastructure, reserves and resources to meet demand in eastern and south-eastern Australia to 2036 Assess impact of gas supply on generation supply adequacy in the electricity market CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 29

30 DOMESTIC GAS PRODUCTION (EXCLUDING LNG), EASTERN AND SOUTH-EASTERN AUSTRALIA Annual domestic gas production to decline by 122 PJ to 2021 with gas supply shortfalls projected Need additional supply Uncertainty - contingent and prospective resources Longer term, infrastructure plant and pipeline capacity constraints limit supply as GPG demand increases Production decline steepest in Victoria - 38% decline between CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 30

31 GAS OR ELECTRICITY SHORTFALLS? Estimated average electricity supply shortfalls of up to 363 GWh may be experienced in , and ` Shortfalls in gas-powered generation expected: SA from (up to 37 PJ in 2021) NSW from (up to 15 PJ in 2019) VIC in 2021 (2 PJ) QLD (up to 54 PJ in 2035) CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 31

32 POSSIBLE SOLUTIONS TO SHORT TERM SHORTFALLS Energy reliability and security could be improved through industry responses, if the market provides incentives for industry to increase gas supply or reduce demand. Some possible options being considered by industry include: Redirecting a small portion of LNG supply to the domestic market. Increasing production from existing fields. Exploring and developing new fields Building the Northern Gas Pipeline to access gas in Northern Territory Developing the proposed Narrabri Gas Project Investing in alternative electricity generation and storage technologies Some of these options would require changes in state and territory energy policies to lift moratoria on hydraulic fracturing, or onshore gas development. CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 32

33 Energy Supply Outlook Gas and Electricity CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 33

34 QUESTIONS? Phone: (03) CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 34

35 2017 VICTORIAN GAS PLANNING REPORT 10 May 17 PRESENTED BY JESSIE YEUNG CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 35

36 WHAT IS THE VICTORIAN GAS PLANNING REPORT? Available at: CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 36

37 VGPR: FIVE YEAR OUTLOOK Supply and demand balance System adequacy Emerging capacity limitations CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 37

38 OVERVIEW 1. SUPPLY ADEQUACY 2. DEMAND DISTRIBUTION 3. THREAT TO SYSTEM SECURITY: SWP TO PORT CAMPBELL 4. THREAT TO SYSTEM SECURITY: WARRAGUL PEAK DAY SUPPLY Warragul CTM CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 38

39 SUPPLY ADEQUACY AND DEMAND DISTRIBUTION CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 39

40 ANNUAL PRODUCTION 34% decline in Gippsland 81% decline in Port Campbell CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 40

41 PEAK DAY SUPPLY AND DEMAND CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 41

42 FORECAST 1-IN-20 PEAK DAY SYSTEM DEMAND CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 42

43 CHANGING LOAD PROFILES Mernda Melton South Cranbourne CTMs CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 Source: Australian Bureau of Statistics. Victoria Regional Population Growth, Australia, SLIDE 43

44 THREAT TO SYSTEM SECURITY: SOUTH WEST PIPELINE TO PORT CAMPBELL CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 44

45 THREAT TO SYSTEM SECURITY ISSUED ON 10 MARCH 2017 CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 45

46 Net withdrawal quantity (PJ/yr) SOUTH WEST PIPELINE TO PORT CAMPBELL FORECAST ANNUAL FLOWS Forecast flows provided by Participants Historical Forecast CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 46

47 SOUTH WEST PIPELINE TO PORT CAMPBELL FORECAST DAILY FLOW BY MONTH Current SWP capacity CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 47

48 DTS CAPACITY LIMITATION Gas flow: High pressure Low pressure High pressure SWP Operating pressure ~ 6,500 kpa MAOP 10,200 Kpa Melbourne MAOP 2,760 kpa LMP MAOP 6,890 kpa Brooklyn Compressor Station CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 48

49 SIMPLIFIED EXISTING BROOKLYN CS CONFIGURATION Gas is compressed unnecessarily to Geelong. Flow controlled by a city gate CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 49

50 PROPOSED AUGMENTATION DTS Service Providers Access Arrangement submission: 1. Reconfigure Brooklyn Compressor Station 2. Bi-directional compressibility at Winchelsea CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 50

51 BROOKLYN CS RECONFIGURATION FLOW TO PORT CAMPBELL Gas compressed directly into SWP. Geelong demand supported as required by BCP city gate. BCP City Gate CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 51

52 BROOKLYN CS RECONFIGURATION FLOW TO PORT CAMPBELL AND LAVERTON NORTH Flow paths can be separated between the SWP and the BCP. CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 52

53 BROOKLYN RECONFIGURATION AND WINCHELSEA BI-DIRECTIONAL COMPRESSIBILITY Proposed augmentation CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 53

54 FORECAST FLOWS BEYOND 2020 Declining production Increase demand in Port Campbell region CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 54

55 SHORT AND LONG TERM DEVELOPMENT Western Outer Ring Main (WORM) Max flow ~ 245 TJ/d Approx. Brooklyn 50km of pipeline Reconfiguration from Wollert max to flow Plumpton = 147 TJ/d New compressor High pressure at Wollert Low pressure High pressure WORM MAOP 10,200 kpa Outer Ring Main MAOP 6,890 kpa SWP MAOP 10,200 kpa Melbourne MAOP 2,760 kpa LMP MAOP 6,890 kpa CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 55

56 SHORT AND LONG TERM DEVELOPMENT Western Outer Ring Main (WORM) Increases capacity from Port Campbell to Melbourne Supports changing load profiles in the DTS and GPG demand Reduces possibility of gas load curtailment during a Longford outage CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 56

57 PROPOSED SOLUTIONS Short term Brooklyn reconfiguration Winchelsea bi-directional compressibility Long term Western Outer Ring Main Additional compression at Wollert CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 57

58 THREAT TO SYSTEM SECURITY: WARRAGUL PEAK DAY SUPPLY CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 58

59 THREAT TO SYSTEM SECURITY ISSUED ON 10 MARCH 2017 CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 59

60 WARRAGUL SUPPLY Dandenong Terminal Station Longford to Melbourne pipeline Lurgi pipeline Warragul CTM Warragul CTM Morwell City Gate Operating strategy: Increase flow at Morwell City Gate Flows from Dandenong Terminal Station Proposed Warragul augmentation: Temporary contractual pressure lateral Loop 4.7 the Warragul of 1,150 kpa km existing of mm km pipe lateral during After augmentation return minimum Maximum flow ~ 10 kscm/hr contractual pressure to 1,400 kpa. CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 60

61 WARRAGUL 1-IN-20 PEAK DAY DEMAND FORECAST Load increase in Tariff D demand in 2017 and CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 61

62 PEAK DAY OCCURS IN Forecast peak day Day ahead schedule (i.e. D+1) Involuntary curtailment of Tariff D demand. 2. Unforecast peak day Involuntary curtailment of Tariff D demand. Breach minimum pressure of 1,150 kpa. Possible loss of supply to Tariff V (residential) demand. CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 62

63 SUMMARY 1. DECLINING PRODUCTION 2. CHANGING LOAD PROFILES 3. IMPACTS TO STORAGE INVENTORY FROM POSSIBLE PRESSURE BREACH AT WARRAGUL IN 2019 Warragul CTM CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 63

64 THANK YOU Contact details: Jessie Yeung Gas Operations Analyst Australian Energy Market Operator T: E: CONFIDENTIAL AND NOT FOR CIRCULATION: THIS INFORMATION IS STRICTLY EMBARGOED UNTIL 09 MARCH 2017 SLIDE 64

65 victorian transmission system access arrangement revision proposal AEMO Gas Winter Outlook May 2017 Alex Curran Regulatory Manager

66 overview revision proposal key themes capital base and forecast capital expenditure demand, cost allocation and pricing 66

67 revision proposal key themes 16/05/

68 revision proposal key themes Responsiveness to customer demand Significant new gas flows north to NSW and Queensland Investments for the future Future growth through Western Outer Ring Main easement purchase, and now the WORM project in the period Safety and integrity spending Possible changes to the policy environment New market structures under policy consideration Consistency with current arrangements Consistency in tariff structure and how costs are allocated to tariffs 68

69 capital base and forecast capital expenditure 16/05/2017

70 capital base and capital expenditure VTS regulatory capital base at 1 January 2018 is $1,005 billion Expenditure in current period higher than forecast Driven by expansion to accommodate increased demand for capacity for gas flows north to NSW and Queensland (VNIE project) Increase from incremental 30TJ/day demand for firm capacity at Culcairn to 149TJ/day Total VNIE project expenditure $299 million (approved was $46.4 million) Total forecast capital expenditure in proposal $168.4 million Anglesea pipeline - $17.4m Warragul - $7.6m Westbound expansion of SWP - $3.5m Western Outer Ring Main (WORM) easement acquisition - $26.7m Subsequent proposal to complete WORM within period (by end 2020) Total proposed WORM expenditure - $122.4m (includes easement costs) 70

71 demand, cost allocation and pricing 16/05/

72 historic and forecast demand trends PJ Tariff V Tariff D Culcairn GPG PJ Total - all Total Tariff-D & Tariff-V 72

73 cost allocation and pricing APA VTS has retained tariff and cost allocation structure from current period Transmission tariffs apply to injections and withdrawals separately In VTS gas ownership can change within the system through the operation of the wholesale gas market Shippers do not contract for point to point transportation Injection tariffs recover the cost of transportation of gas from injection points to a nominal hub Hub considered as the Melbourne metro area Withdrawal tariffs recover the cost of transportation of gas from the hub to its withdrawal location Includes transportation within or across the Melbourne metro area Each delivery (withdrawal) point is allocated to a withdrawal zone Demand is split between Tariff D (large industrial) and Tariff V (residential and small business) within each zone 73

74 VNI expansion cost allocation VNI expansion Capacity related system capital costs Locational Allocated to asset zone Allocated to Culcairn withdrawal tariff All within Tariff-D class (no small customer capex allocation) Increased VNIE expenditure and volumes takes additional proportional share of non locational costs (eg. non-system capital, corporate, etc) Victorian domestic customers do not bear the costs of VNI expansion and receive benefit from reduced allocation of common costs Culcairn allocated $5m of indirect costs that would otherwise be shared throughout the system 74

75 For further information contact: Alex Curran Regulatory Manager Or visit the APA website at: 75

76 Australian Energy Regulator The Gas Transmission System over the next 5 years AEMO Victorian Gas Operations Outlook Conference Winter 2017 Sebastian Roberts GM Network Expenditure

77 Overview APA reset proposal and process Submissions key themes AEMC review of DWGM

78 APA proposal On 3 January, APA submitted its Victorian Transmission System access arrangement proposal. Key features compared to the previous period: Forecast revenue requirement is $709.3m - up 43.8%. Proposed rate of return is 7.88% - above current rate Forecast capex is $168.4m - down almost 60% compared to actual capex expenditure. Forecast opex is $132 million - up 1.8%.

79 Step Reset timeline Date Access arrangement proposal submitted to AER 3 January 2017 Proposal published 10 January 2017 Public forum on access arrangement proposal 1 February 2017 Submissions on proposal closed 3 March 2017 AER to publish draft decision 29 June 2017 Revised proposals submitted 14 August 2017 Stakeholder submissions on draft decisions and revised proposals 12 September 2017 AER to issue final decision 30 November 2017 Revised access arrangements commence 1 January 2018

80 Market Developments LNG - tightening market for gas with price increases LNG - Northward flow of gas Release of GSOO and VGPR by AEMO and the issuing of 2 threats to system security (SWP and Warragul) Closure of the Hazelwood power plant and increased GPG in Victoria Reviews Vertigan, AEMC, ACCC, Finkel

81 Submissions Key Themes 14 submissions Key issues 1. SWP a. Refill of Iona Underground Gas Storage facility b. Western Outer Ring Main 2. Warragul Lateral Expansion 3. Culcairn withdrawal tariff - Vic Northern Interconnect expansion

82 APA investment - track record

83 SWP and Western Outer Ring Main The WORM provides a link between the east and west, creating a high pressure ring around Melbourne ($ million) APA AA submission proposes pre-purchase of the WORM easements Following the stakeholder comments, APA are now proposing to build the WORM in the AA period. APA last week provided a business case for the WORM. The AER will consult on the proposal.

84 Northern Interconnector The AER s 2012 decision accommodated $85m for northern expansion APA spent $339 Victorian user concerns that expansion may add to their tariffs in future AER is considering the expansion according to the requirements of the NGR

85 Warragul Lateral Expansion Involves looping of 4.8 km of the Warragul Lateral pipeline Project has become increasingly urgent (AEMO has issued threat to system security notice) AER has approved this capex in 2 previous AAs, but APA is yet to undertake the work.

86 AEMC Review of DWGM The AEMC s draft decision recommended radical reform of the DMGM These reforms would have been difficult to implement The AER encourages the AEMC to adopt more incremental change A number of beneficial modifications that can be made to the current DWGM in the short term, including: Options to create forward trading, improvements to uplift allocation Incentive based regulatory framework is informed by extensive consultation and seems to be delivering efficient investment outcomes Should AEMO have a greater say in investment decision?

87 ACCC review into gas market ACCC inquiry into gas pricing and supply Strongly support moves to increase transparency in the gas market Australian Domestic Gas Supply Mechanism Shortfall of domestic supply: importance of understanding domestic exploration and production Fairly reflect international export prices: importance of deriving export parity pricing ACCC release reports First due October 2017

88 Questions?

89 WINTER 2017 VICTORIAN GAS OPERATIONS OUTLOOK 10 May 2017 SLIDE 89

90 AGENDA 10:30-11:20 Session 1 Future Gas Supply and Demand Introduction (AEMO) National Gas Forecasting Report (AEMO) Gas Statement of Opportunities (AEMO) Victorian Gas Planning Report (AEMO) 11:20-12:00 Session 2 Transmission System next 5 years APA s VTS Regulatory Proposal (APA) AER s Regulatory Determination (AER) 12:00-1:00 Lunch SLIDE 90

91 AGENDA 1:00-3:00 Session 3 Winter Operations 2016 Winter Review (AEMO) 2017 Weather Outlook (Weatherzone) 2017 APA Augmentations (APA) Transmission Operations (AEMO) 3:00-3:30 Afternoon Tea 3:30-5:00 Session 4 Market and Emergency Operations Abnormal Market Operations (AEMO) Emergency Operations (AEMO) Summary of Key Messages (AEMO) 5:00-6:00 Networking SLIDE 91

92 WINTER 2016 REVIEW Presented by Luke Garland Manager, AEMO Gas System Operations SLIDE 92

93 AGENDA 1. Yearly Trend 2. Winter 2016 in review 3. Market Interactions SLIDE 93

94 DEMAND AND CONSUMPTION TREND Approximately 60% of annual consumption occurs in winter Annual consumption has on average trended down Peak demand days have been relatively consistent from 2013 SLIDE 94

95 EDD TRENDS SLIDE 95

96 EDD TRENDS YTD ANZAC Day /03 14/03 18/03 22/03 26/03 30/03 03/04 07/04 11/04 15/04 19/04 23/04 27/04 01/05 05/ SLIDE 96

97 WINTER 2016 IN REVIEW Winter Period is 1 May 30 September, The 2016 peak demand days for the DTS included; o 1,187 TJ on 24 June 2016 o 1,162 TJ on 13 July 2016 o 1,140 TJ on 26 July 2016 o Peak GPG demand day occurred on 7 July of 111 TJ Esso injections profiled on the top two demand days. SLIDE 97

98 WINTER 2016 IN REVIEW Comparing peak days Sunday had a 0.2 degree higher EDD, but used 109 TJ less in System Demand due to the day of the week SLIDE 98

99 24 & 26 JUNE COMPARISON SLIDE 99

100 24 & 26 JUNE COMPARISON SLIDE 100

101 SUPPLY TIGHTNESS With the East Coast supply tightening, what is happening in the market? SLIDE 101

102 Quantity (TJ) STORAGE UTILISATION 25,000 Iona Underground Storage Level 20,000 15,000 10,000 Less than 50% Storage by end of June 2016 Currently 82% full 5,000 - Less than 30% Storage by start of September 2016 Date Est. Storage Gas BB INT930 Max Capacity SLIDE 102

103 Quantity (Tonnes) STORAGE UTILISATION Dandenong LNG Storage Level 12,000 10,000 8,000 6,000 4,000 2,000 - LNG also used heavily during June October % of tank used in 1 day Market response LNG used by participants LNG Storage Date Max Capacity SLIDE 103

104 DWGM BOD MARKET PRICE SLIDE 104

105 DWGM BOD MARKET PRICE SLIDE 105

106 DWGM BOD MARKET PRICE SLIDE 106

107 DWGM BOD MARKET PRICE 13 July June 2016 SLIDE 107

108 MARKET INTERACTIONS SLIDE 108

109 QUESTIONS? SLIDE 109

110 WINTER OUTLOOK Victorian Gas Operations May 2017 Josh Fisher - Meteorologist/Energy Account Manager SLIDE 110

111 Overview Review of winter 2016 State of the climate Outlook for winter 2017 SLIDE 111

112 Winter Review 2016 Weatherzone Long Range Verification SLIDE 112

113 Climate Drivers SLIDE 113

114 ENSO NINO3.4 Index = Average SSTs across the 3.4 region SOI = Atmospheric pressure difference between Darwin and Tahiti SLIDE 114

115 ENSO Outlook - NINO3.4 Index Current International Consensus May NINO3.4 Index: 0.5 July NINO3.4 Index: 0.8 September NINO3.4 Index: 1.0 For a La Nina (-0.8)/El Nino (+0.8) to be declared, thresholds need to be met for at least 3 consecutive months SLIDE 115

116 Indian Ocean Dipole - Positive Phase SLIDE 116

117 Sea Surface Temperatures SLIDE 117

118 Climate Drivers SLIDE 118

119 ENSO conditions = Neutral (El Nino watch) IOD = Neutral (Positive risk) Climate Summary SSTs= Very warm in the east, cooling in the west No real large scale drivers likely to dominate winter conditions. SLIDE 119

120 National Outlook - JJA Maximum s Minimum s Decile SLIDE 120

121 National Outlook - JJA Rainfal l Decile SLIDE 121

122 MELBOURNE - Temperatures Maximum s Minimum s Forecast Anomaly ( mean) SLIDE 122

123 MELBOURNE - Temperatures Days < 12C EDDs SLIDE 123

124 Numerical models continue to suggest a warming of the Pacific Ocean in Outlook Summary WINTER Increase risk in El Nino-like conditions during winter: - Decreased cloud cover across the east - Below Average Rainfall - Warmer than average daytime temperatures - Though cooler nights across inland areas are possible - More mobile weather systems - Potential for greater variability in temperatures and near normal amount of cold days Positive IOD is also a chance: - Reinforces ENSO conditions, mainly towards the end of winter SLIDE 124

125 Josh Fisher Weatherzone Level 5, 8 West Street North Sydney NSW 2065 T E jfisher@weatherzone.com.au Questions? SLIDE 125

126 APA Victorian Transmission System Winter 2017 Operations Outlook System Augmentations and Modifications 10 May 2017

127 Overview Victorian Transmission System Summary / Overview Current DTS / VTS Existing Capacities Victorian Northern Interconnect (VNI) Summary / Overview Modifications, Enhancements and Augmentations Proposed Augmentations access arrangement 5 (2018 to 2022) Warragul Augmentation Anglesea Pipeline Extension SWP Expansion (to Port Campbell) WORM Project 127

128 Victorian Transmission System Summary / Overview System and Pipeline Capacities 128

129 APA Victorian Gas Transmission System overview Gas Supply Sources Esso Longford Cooper and Seven Group via VicHub (&TasHub) Port/Campbell/Iona also connection to Adelaide via SEAGas Queensland gas via Moomba Sydney Pipeline at Culcairn Culcairn south flow from MSP to Victoria Pakenham BassGas APA Dandenong LNG (DLNG) Pipeline Import Capacity (TJ/d) Longford Pipeline 990-1,030 (VicHub/TasHub/BassGas) Export Capacity (TJ/d) Up to 135 (VicHub) South West Pipeline Up to 412 Up to 104 (non-winter) Northern Pipeline (2016) Northern Pipeline (2017) Up to 125 Up to 125 Up to 153 (summer) Up to 148 (winter) Up to 200 (summer) Up to 223 (winter) Western System n/a 129

130 Current DTS / VTS Existing Capacities Source: AEMO Victorian Gas Planning Report

131 Victorian Northern Interconnect Summary / Overview Modifications, Enhancements and Augmentations 131

132 Post VNI (May 2017) Import and Export Capacities VNI Looping (400mm; #900) (Final Stage 258.9km (+39.4)) Project to loop Broadford to Tallarook (13.9km) Project to loop Glenrowan to Wangaratta North (25.5km) Modifications at Euroa PRS, Barnawartha PRS and Wollert PRS Looping in NSW Source: AEMO Victorian Gas Planning Report

133 APA s Victorian Northern Interconnect (VNI) - SUPERHIGHWAY 133

134 Proposed Augmentations business case AA5 access arrangement to

135 Proposed VTS Augmentation - access arrangement projects Source: AEMO Victorian Gas Planning Report

136 Proposed VTS Augmentation - Brooklyn and Winchelsea APA has proposed in AA5 a $3.5 m expansion including Brooklyn Compressor Reconfiguration & Winchelsea Compressor bidirectionality APA capacity expansion Achieves additional capacity of 50 TJ/d of SWP western haul (refill) capacity by Mar 2018 Solution matches current Iona refill capacity but refill may be interrupted if GPG operates more frequently APA ready for early construction start pending a positive draft decision from AER 136

137 Interim solution Relife of Mothballed Brooklyn Compressor Background Brooklyn Compressor Station (BCS) units 11 and 12 currently supply capacity to the South West Pipeline (Iona refill) BCS Unit10 has not run for 9 years, is only an emergency back up to units 11 or 12 Proposal Carry out major service and minor repairs, approximate cost $150K Provides interim solution to ensure that there is sufficient capacity for Iona refill if there are unexpectedly high draws on Iona capacity (eg to support South Australia) Standby required for period June 2017 to March 2018 (until VTS Augmentation at Brooklyn (prior slide) in operation) Issues to resolve Licensing issues to be addressed including EPA (NOx, noise) and of ESV (wet seals and liquid injection) APA working with authorities to resolve 137

138 Long term solution - Western Outer Ring Main (WORM) Capital Expenditure $122.4m; completed end 2020 Proposed in last AA as necessary for security of supply AER did not approve the proposal Adds 70TJ towards Iona (max capacity 220TJ/D) Half the fuel gas will be required, compared to the current quantity used for transportation via Brooklyn CS Addresses ageing infrastructure at Brooklyn with urban encroachment an additional challenge to its operations With the additional compression 470TJ to Melbourne demand zone Supports localised GPG Newport (EA) Somerton (AGL) and Laverton (Snowy) Source: AEMO Victorian Gas Planning Report 2017 Long term solution for Security of Supply for Victoria. 138

139 Additional peak day support Dandenong LNG facility APA Victorian Northern Interconnect 125TJ/day to Victoria Storage products for industrials and retailers to manage NSW and Victorian demand peak loads New injection point TasHub 120TJ/day with expansion to 240TJ/day for peak day system support Additional compression on the South West Pipeline (e.g. Stonehaven) 139

140 Questions? For further information contact: Name: Daniel Tucci Title: Infrastructure Development - Senior Concept Engineer Tel: / daniel.tucci@apa.com.au Or visit the APA website at: 140

141 10 May 2017 VICTORIAN GAS WINTER OUTLOOK 2017 TRANSMISSION OPERATIONS PRESENTED BY TRENT SHINNERS SLIDE 141

142 AGENDA 1. Victorian Declared Transmission System (DTS) Operations Overview 2. Linepack Adequacy Defined Winter Period (01 May to 30 September) 3. Supply and Demand Outlook Changing Demand Profile Gas Powered Generation Changing Flow Direction What are the challenges? How do we manage them? SLIDE 142

143 Summer Operations Winter Operations SLIDE 143

144 VICTORIAN DTS SLIDE 144

145 VICTORIAN DTS South West Pipeline Northern (VNI) Typical Winter Flow Longford (LMP) Compressor Station + City Gate 2016 Max = 900 TJ City Gate Compressor Station Gas Powered Generator (GPG) 2016 Max = 331 TJ % 2016 Avg = 789 TJ 2016 Max = 105 TJ 2016 Avg = 141 TJ 2016 Avg = 47TJ 5 % % % 2 % % SLIDE 145

146 VICTORIAN DTS South West Pipeline Northern (VNI) Alternative Winter Flow Longford (LMP) Compressor Station + City Gate City Gate Dynamic system, multiple flow paths, differing capacities Compressor Station Gas Powered Generator (GPG) 2016 Max = 87 TJ Average capacity = 64 TJ Melbourne Zone consumes ~65 % VIC demand 2016 Avg = 55 TJ 2016 Max = 35 TJ 2016 Avg = 14 TJ Longford To Melbourne Pipeline (LMP) ~70 to 90 % supply South West Pipeline (SWP) and Victorian Northern Interconnect (VNI) flow in both directions in Winter SLIDE 146

147 AGENDA 1. Victorian Declared Transmission System (DTS) Operations Overview 2. Linepack Adequacy 3. Supply and Demand Outlook Changing Demand Profile Gas Powered Generation Changing Flow Direction SLIDE 147

148 Pipeline pressure WHAT IS LINEPACK? Supply reduction Supply point Winter Increase = Higher flow rate Demand = increase = Higher pressure Gas drop Flow = Less PipeLINE Usable Transport PACKed Linepack Demand > Supply = Consume linepack Demand increase Demand point Max Pressure Active Usable Linepack Max injection pressure determines max active linepack Active (not usable) Min Pressure Passive required to maintain continuous supply Distance along pipeline SLIDE 148

149 DTS LINEPACK VS OTHER PIPELINES NSW/ ACT demand supplied by two major pipelines. Victorian Winter: Minimal time to respond to a major supply failure If major supply failure, usable linepack could support NSW/ACT demand for up to three days VIC demand supplied by one small interconnected network. If major supply failure, usable linepack could support VIC demand for two to four hours. SLIDE 149

150 SETTING END OF DAY (EOD) LINEPACK TARGET *Not including pipeline Peak Winter (Active) Linepack Target = 425 TJ maintenance and projects Higher LP due to VNI duplication SLIDE 150

151 Pipeline pressure USABLE LINEPACK PEAK WINTER (ACTIVE) LINEPACK = 425 TJ Max pressure ACTIVE (NOT USABLE) Min pressure Passive Distance along pipeline SLIDE 151

152 IDEAL BEGINNING OF DAY (BOD) USABLE LINEPACK BALANCE USABLE LINEPACK 220 TJ Max (80) ~25 % *Remaining 20 TJ spread throughout smaller pipelines 50 TJ Max (90) ~25 % Min (0) Max (140) ~50 % 50 TJ 100 TJ Min (0) Min (0) SLIDE 152

153 AGENDA 1. Victorian Declared Transmission System (DTS) Operations Overview 2. Linepack Adequacy 3. Supply and Demand Outlook Changing Demand Profile Gas Powered Generation Changing Flow Direction SLIDE 153

154 SUPPLY DEMAND ADEQUACY To supply interconnected pipelines and forecast GPG (593 extra) Total = 1903 To support forecast GPG (161 extra) Total = 1471 Adequate System Capacity for forecast peak demand *based on perfect forecast and starting conditions Limited System Capacity for surprise demand or unforecast GPG 1 in 20 = 1310 TJ 1 in 2 = 1198 TJ Since % < 1000 TJ SLIDE 154

155 AGENDA 1. Victorian Declared Transmission System (DTS) Operations Overview 2. Linepack Adequacy 3. Supply and Demand Outlook Changing Demand Profile Gas Powered Generation Changing Flow Direction SLIDE 155

156 DEMAND PROFILE 8 sunshine hours 4 sunshine hours Higher Peaks Morning Peak Evening Peak Lower Troughs 300 TJ 900 TJ 1184 TJ 1310 TJ 900 TJ SLIDE 156

157 IMPACT OF PEAKY DAYS ON LINEPACK By 10:00 PM Gas Day Hours = 16 / 24 = 67 % Total Injections (flat) = 67 % Using Total Withdrawals Building(variable) = Using ~80% Peakier days = Building more usable linepack consumed. Flat injections SLIDE 157

158 AGENDA 1. Victorian Declared Transmission System (DTS) Operations 2. Linepack Adequacy 3. Supply and Demand Outlook Changing Demand Profile Gas Powered Generation Changing Flow Direction SLIDE 158

159 DTS GAS POWERED GENERATORS May come online quickly in large quantities (23 TJ/h) May come online unforecast Typical profile increases over morning and evening peaks Laverton North 344 MW Newport 515 MW Somerton 170 MW Jeeralang 560 MW Valley Power 360 MW Total ~23 TJ/h SLIDE 159

160 No GPG Forecast GPG Unforecast GPG Impact of only 75TJ unforecast GPG on an average winter demand day 75 TJ of usable linepack left....not a lot! System Demand Total Demand Injections (no GPG) Injections (Unforecast GPG) Injections (forecast GPG) SLIDE 160

161 GAS POWERED GENERATION (GPG) OUTLOOK 2007: Highest ever Winter GPG usage 2017: Hazelwood shutdown April 2017 Max = 154 TJ Forecast SLIDE 161

162 WHAT HAPPENED IN 2007? Water restrictions for hydroelectric and coal-fired generation led to substantially higher GPG demand. SLIDE 162

163 WHAT DID THE DTS LOOK LIKE IN 2007? So how was the DTS managed? No VNI duplication No Euroa CS No Winchelsea CS No Wollert B CS No TasHub No Otway No Brooklyn-Lara Pipeline SLIDE 163

164 WINTER LNG UTILISATION LNG Storage Capacity Used 43 % of total storage capacity by end June (mid winter!) Market implemented other strategies to preserve LNG inventory. e.g. Profiled Iona Injections SLIDE 164

165 DTS IN 2017 Greater flexibility Duplicated VNI Euroa CS Winchelsea CS Otway Wollert B CS Reconfigured Wollert CG & PRS Extra injection sources TasHub Increased Capacity Brooklyn-Lara Pipeline SLIDE 165

166 GPG IMPACT 2007 VS 2017 CHALLENGES Tighter east coast gas supply ADVANTAGES Better equipped gas system Changing load profile MARKET PARTICIPANTS Good forecasting Good communication SLIDE 166

167 AGENDA 1. Victorian Declared Transmission System (DTS) Operations 2. Linepack Adequacy 3. Supply and Demand Outlook Changing Demand Profile Gas Powered Generation Changing Flow Direction SLIDE 167

168 CHANGING FLOW DIRECTION Significant increase of variability QLD ramp gas SLIDE 168

169 01 May 30 Sep 01 May 30 Sep Winter 2015 Winter 2016 SLIDE 169

170 SWP WINTER NET FLOW System Demand = 500 to 800 TJ (~50 % of the time) SWP could be injecting up to 150 TJ/d or withdrawing up to 100 TJ/d. Demand > 800TJ = Only Injections Demand < 500TJ = Only Withdrawals SLIDE 170

171 IMPACT OF FLOW DIRECTION CHANGES SWP INJECTIONS SWP WITHDRAWALS Maximum Brooklyn CS Discharge Pressure 8500 kpa 7000 kpa 4500 kpa 6500 kpa USABLE (~50TJ) NO USABLE LINEPACK PASSIVE LINEPACK PASSIVE LINEPACK Iona Brooklyn Iona Brooklyn SLIDE 171

172 MANAGING SWP SWINGS..therefore, unable to increase EOD LP Target higher than 425TJ Max (90) VNI injections get backed off Max (80) TJ Very little room for overforecasting or overinjection. Min (0) Max (140) Min (0) 500 TJ No usable LP when SWP withdrawing Extra 50 TJ ends up in LMP and VNI Min (0) TJ BassGas & Longford Gas Plant injections get backed off SLIDE 172

173 REDUCING LINEPACK TARGET Benefit: Prevent high pressure events at injections points due to overforecasting Risk: Insufficient linepack available for surprise demand or unforecast GPG. SLIDE 173

174 VNI WINTER NET FLOW System Demand = 700 to 1100 TJ (~62 % of the time) VNI could be importing up to 50 TJ/d or exporting up to 100 TJ/d. Demand > 1100TJ = Only Injections Demand < 700 TJ = Only Withdrawals SLIDE 174

175 MANAGING VNI SWINGS VNI EXPORTS Increase VNI LP to support Exports may be impacted if pressure too low exports VNI IMPORTS Imports may be impacted if pressure too high Reduce VNI LP Operate Wollert, Euroa and Springhurst CS northbound 65 TJ Operate Springhurst and Euroa CS southbound 25 TJ Max build or mine rate 4-8 TJ/h LP is taken from LMP Less Utilise LP SWP available, LP, Higher preserve chance LMP LP of LNG to support requirement GPG Store extra LP in LMP to support GPG SLIDE 175

176 AGENDA 1. Victorian Declared Transmission System (DTS) Operations Overview 2. Linepack Adequacy 3. Supply and Demand Outlook Changing Demand Profile Gas Powered Generation Changing Flow Direction What are the challenges? How do we manage them? SLIDE 176

177 PREVENTATIVE MEASURES What have we touched on? What else do we do? Manage system linepack Monitor GPG forecasts (NEM Pre Despatch) and communicate with NEM control room Demand override methodology (Luke Stevens, AEMO) ESSO Injection Profiling If D+1 Demand > 1150 TJ Monitor storage inventory Consult with ESSO & Jemena prior to 4:00 PM D+1 schedule Extra 2 TJ/h for 14 hours Extra 28 TJ by 10:00 PM SLIDE 177

178 ESSO PROFILED INJECTIONS 12 July July TJ low on LP Used 150 TJ LP Temp drop 3 C in 3 hours Injection facility deviation 115 TJ lower LP Forecast = 1180 TJ LP Target Only 50 TJ Usable LP to support surprise demand 3 C warmer across or GPG peak than yesterday MP overforecast MP 28 underforecast TJ extra from morning profiled ESSO injections MP underforecast from 4PM Injections ramp up Actual System Demand MP Forecast Demand Actual Injections Injections (ex ESSO profile) System Linepack SLIDE 178 System Linepack (ex ESSO)

179 OPERATIONAL RESPONSE Peak Shaving LNG (Ad hoc schedule) Direction Curtailment Market Operations (Luke Stevens, AEMO) Used when models indicate LNG requirement to maintain minimum system linepack Firm rate 5.5 TJ/h Max rate 9.8 TJ/h or 87 TJ/d SLIDE 179

180 OPERATIONAL RESPONSE LNG Run 2:00 models PM NEM Event Breach Unforecast 21 TJ at of 8:30 LNG GPG PM 13 TJ/h Firm Potentially rate ( for entire TJ/h) evening for 4 hours peak from 4:00 PM No GPG forecast Ad hoc schedule Already Injections profiled respond ESSO to what injections has occurred SLIDE 180

181 SUMMARY Declared Transmission System Several demand zones, Melbourne 65% Dynamic & bidirectional flow, differing pipeline capacities SLIDE 181

182 SUMMARY Linepack Adequacy If major supply failure, 2 4 hours survival time peak winter Limited usable linepack for unforecast demand or GPG SLIDE 182

183 SUMMARY Supply and Demand Outlook Adequate System Capacity for forecast peak demand day Limited System Capacity for unforecast demand or GPG SLIDE 183

184 SUMMARY What s different? Peakier demand profiles Increased flow direction changes Increased GPG forecast SLIDE 184

185 SUMMARY AEMO Preparedness Better equipped gas system Preventative Measures Monitor storage inventory Monitor GPG forecasts Demand override methodology ESSO Injection Profiling Effective linepack management strategies Operational Response Peak Shaving LNG Direction Curtailment SLIDE 185

186 SUMMARY Market Participants Good forecasting Good communication SLIDE 186

187 Questions? Contact: SLIDE 187

188 VICTORIAN GAS OPERATIONS - WINTER MARKET OPERATIONS 10 May 2017 PRESENTED BY LUKE STEVENS SLIDE 188

189 OVERVIEW Market Operations Demand Forecast o Weather o GPG Demand Forecast Override Constraints Winter and Abnormal Market Operations Longford Profiling Responding to Threats Curtailment Market Suspension Market Administration SLIDE 189

190 DEMAND FORECAST SLIDE 190

191 DEMAND FORECAST UNCERTAINTY - TOTAL DEMAND FORECAST Total Demand System Demand GPG Demand SLIDE 191

192 System Demand DEMAND FORECAST UNCERTAINTY SYSTEM DEMAND AND WEATHER Effective Degree Day (EDD) Average Temperature, Wind Speed, Sunshine Hours Inverse magnitude to Average Temperature EDD = 0 C T = 18 C Heating Load Base Load Average Temperature SLIDE 192

193 DEMAND FORECAST UNCERTAINTY EDD AND DEMAND WINTER 2016 SLIDE 193

194 DEMAND FORECAST UNCERTAINTY MONITORING WEATHER :00 AM 10:00 AM 2:00 PM 6:00 PM 10:00 PM 5:00 AM Participant Forecast AEMO Actual Monitor Weather Demand Forecast Demand Profile SLIDE 194

195 DEMAND FORECAST UNCERTAINTY MONITORING GPG DEMAND SLIDE 195

196 DEMAND FORECAST UNCERTAINTY MANAGE GPG DEMAND SLIDE 196

197 DEMAND FORECAST UNCERTAINTY MONTHLY GPG DEMAND FORECAST Mild summer temperatures Actual demand close to forecast Historically high hydro and wind generation month SLIDE 197

198 FORECAST DEMAND Update your system demand and GPG forecasts! SLIDE 198

199 DEMAND FORECAST OVERRIDE SLIDE 199

200 DEMAND OVERRIDE 24 JUNE 2016 INPUT DATA SLIDE 200

201 DEMAND OVERRIDE 24 JUNE 2016 ADJUST LIMITS SLIDE 201

202 DEMAND OVERRIDE 24 JUNE 2016 ACTUAL AND OVERRIDE Impacts next day BOD linepack SLIDE 202

203 DEMAND OVERRIDES NUMBER OF WINTER OVERRIDES Less overrides after SLIDE 203

204 FORECAST DEMAND A demand override is applied to both forecast system demand and forecast GPG demand! SLIDE 204

205 CONSTRAINTS SLIDE 205

206 CONSTRAINTS WHY ARE THEY IMPORTANT? SLIDE 206

207 CONSTRAINTS WHY ARE THEY IMPORTANT? SLIDE 207

208 CONSTRAINTS SDPC Supply demand point constraint DFPC Directional flow point constraint NFTC Net flow transportation constraint SSC Supply source constraint SLIDE 208

209 CONSTRAINTS SUPPLY DEMAND POINT CONSTRAINT Supply Demand Point Constraint (SDPC) Restrict flow at a facility injection or withdrawal meter Implemented due to maintenance or outage. Applied at any facility injection or withdrawal meter If a threat is identified, is used to force in injections SLIDE 209

210 CONSTRAINTS SUPPLY DEMAND POINT CONSTRAINT SLIDE 210

211 CONSTRAINTS DIRECTIONAL FLOW POINT CONSTRAINT Directional Flow Point Constraint (DFPC) Applied to bi-directional meters to limit net flow DFPC at VicHub, SEAGas and TasHub for 0GJ net withdrawal May be applied at Culcairn, Iona and Otway meters to reflect limit Replaced with SDPC to remove financial flows if a facility has an outage. SLIDE 211

212 CONSTRAINTS NET FLOW TRANSPORTATION CONSTRAINT Net Flow Transportation Constraint (NFTC) Applied to reflect DTS transportation capacity Impacts all facility injection and withdrawal meters on a pipeline Only applied in the Operating Schedule SLIDE 212

213 CONSTRAINTS Net Flow Transportation Constraint SLIDE 213

214 CONSTRAINTS SUPPLY SOURCE CONSTRAINT Supply Source Constraint (SSC) Applied when a meter has multiple supply sources. Register facility to use constraint (eg SEAGas) SLIDE 214

215 CONSTRAINTS Constraints impact market outcomes! SLIDE 215

216 MARKET OPERATIONS SUMMARY Demand forecast o System demand o GPG demand Demand Override Constraints SLIDE 216

217 WINTER AND ABNORMAL MARKET OPERATIONS SLIDE 217

218 OVERVIEW Market Operations Demand Forecast o Weather o GPG Demand Forecast Override Constraints Winter and Abnormal Market Operations Longford Profiling Responding to Threats Curtailment Market Suspension Market Administration SLIDE 218

219 WINTER OPERATIONS SLIDE 219

220 WINTER OPERATIONS - LONGFORD PROFILING Impacts System Market SLIDE 220

221 WINTER OPERATIONS - LONGFORD PROFILING Extra 28 TJ of Linepack by 8PM 2TJ/h for 14 hours No impact on Participant s Imbalances or Deviations. From 8PM injections can vary at Longford SLIDE 221

222 ABNORMAL MARKET OPERATIONS RESPONDING TO THREATS TO SYSTEM SECURITY SLIDE 222

223 RESPONSE TO THREATS TO SYSTEM SECURITY 1. Market response 2. Longford profiling 1. Locational injections 2. Operational LNG; 3. Ad Hoc Schedule 1. Direct additional Injection or reduce withdrawal Before Day <24 Hours <8 Hours <4 Hours <2 Hours Event 1. Market Response 2. Locational Injections 1. Ad Hoc Schedule 2. Direct additional Injection or reduce withdrawal 1. Curtailment 2. Emergency 3. Market Suspension SLIDE 223

224 ABNORMAL MARKET OPERATIONS 1. Market Response 2. Operational Response 3. Ad Hoc Schedule 4. Direction 5. Curtailment 6. Market Suspension SLIDE 224

225 ABNORMAL MARKET OPERATIONS - SCENARIO SLIDE 225

226 ABNORMAL MARKET OPERATIONS - SCENARIO SLIDE 226

227 ABNORMAL MARKET OPERATIONS - SCENARIO SLIDE 227

228 ABNORMAL MARKET OPERATIONS SCENARIO No breach Extra 4TJ/h SLIDE 228

229 ABNORMAL MARKET OPERATIONS - - MARKET RESPONSE SLIDE 229

230 ABNORMAL MARKET OPERATIONS 1. Market Response 2. Operational Response 3. Ad Hoc Schedule 4. Direction 5. Curtailment 6. Market Suspension SLIDE 230

231 ABNORMAL MARKET OPERATIONS - LOCATIONAL INJECTIONS SLIDE 231

232 ABNORMAL MARKET OPERATIONS 1. Market Response 2. Operational Response 3. Ad Hoc Schedule 4. Direction 5. Curtailment 6. Market Suspension SLIDE 232

233 OPERATIONAL RESPONSE LNG SLIDE 233

234 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE SLIDE 234

235 ABNORMAL MARKET OPERATIONS - OPERATIONAL RESPONSE LNG Over multiple horizons First/Last hour 5.0 TJ/hr Firm 5.5TJ/hr (100t/hr) Non-firm 9.9TJ/hr (180t/hr) SLIDE 235

236 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE What about 1 October 2016? SLIDE 236

237 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE 1 OCTOBER 4:28 AM Initial Longford plant trip 4:45 AM Begin to reconfigure the DTS 4:50 AM Longford start to flow some gas 5:30 AM Modelling confirms no threat. 5:37 AM Longford reduces flow to 0TJ/h. 5:47 AM Constraint request for 0 TJ/h until 9:00 AM. 5:53 AM AEMO approves 6:00 AM Schedule. SLIDE 237

238 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE 1 OCTOBER SLIDE 238

239 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE 1 OCTOBER 6:00 AM to 6:40 AM AEMO works with distributors on minimum CTM requirements AEMO reduces DCG outlet pressure below contractual pressures within Melbourne as agreed with Distributors 7:00 AM 8.30 AM discussions with all facility operators 7:00 AM 8:30 AM AEMO modelling potential scenarios for Longford Injection AM decision to proceed with Ad Hoc Schedule SLIDE 239

240 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE 1 OCTOBER SLIDE 240

241 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE 1 OCTOBER 9:03 AM AEMO approves Ad Hoc Schedule 10:12 AM Sale CTM Pressure breach 10:45 AM Longford recommences injections 12:16 PM Sale CTM pressure above minimum pressure SLIDE 241

242 ABNORMAL MARKET OPERATIONS - AD HOC SCHEDULE 1 OCTOBER SLIDE 242

243 ABNORMAL MARKET OPERATIONS 1. Market Response 2. Operational Response 3. Ad Hoc Schedule 4. Direction 5. Curtailment 6. Market Suspension SLIDE 243

244 ABNORMAL MARKET OPERATIONS - DIRECT INJECTIONS SWN of threat NGL 91BC - Directions Direct facility to inject NGR Interventions Change Gas BB linepack flag Publish SWN and MIBB attachment Monitor threat Directed Qty = Deviation Qty Deviation paid at next schedules price NGR 344 Participant Claims NGR 237 Dispute Resolution Panel Compensation procedures SLIDE 244

245 CURTAILMENT SLIDE 245

246 CURTAILMENT SWN and MIBB attachment Curtail GPG and controllable withdrawal AEMO send curtailment instructions to retailers Retailers to commence curtailment Request voluntary end user curtailment NGL 91BC - Directions NGR Interventions NGR 344 Participant Claims NGR 237 Dispute Resolution Panel Compensation procedures Victorian Energy Emergency Communication Protocol Monitor threat SLIDE 246

247 MARKET SUSPENSION SLIDE 247

248 MARKET SUSPENSION Triggers under NGR 347(1): 1. An Emergency 2. Direction of Victorian government 3. AEMO determines it is impossible to operate the Market in accordance with Part 19. Not triggers under NGR 347(2): 1. Market Price at VoLL 2. Issue of an Emergency Direction 3. AEMO Intervention due to a Threat to System Security Trigger Event SWN Start of Market Suspension Administer Market SWN - End of Market Suspension Return to normal Market Operations SLIDE 248

249 ADMINISTERED MARKET SLIDE 249

250 ADMINISTERED MARKET Administered Price Cap = $40/GJ Triggers: 1. Market Suspension 2. Exceeding Cumulative Price Threshold 3. Retailer of last resort (ROLR) event 4. Inability to publish market price or pricing schedule Trigger Event SWN for start of Admin Period Admin price cap ($40/GJ) applied SWN for end of Admin Period Return to normal Market Operations SLIDE 250

251 ABNORMAL MARKET OPERATIONS SUMMARY Longford Profiling Responding to Threats o Market Response o Operational Response o Ad hoc schedule o Directions Curtailment Market Suspension Market Administration SLIDE 251

252 QUESTIONS? SLIDE 252

253 10 May 2017 EMERGENCY MANAGEMENT IN THE DWGM PRESENTED BY MARK POLLOCK SLIDE 253

254 PURPOSE AEMO s operational response AEMO s management response Emergency Management Team structures Communication Protocols SLIDE 254

255 AEMO S RESPONSIBILITIES & POWERS National Gas Law Section 91BA AEMO s responsibility for operation and security of DTS Section 91BC AEMO s powers to direct participants, up to and including curtailment National Gas Rules Rule 339 Rule 341 Rule 342 Rule 343 Declarations and directions in an emergency Notice of threat to system security Market response to threat to system security Intervention due to system security threat SLIDE 255

256 GAS EMERGENCY PROTOCOL Wholesale Market System Security Procedures Emergency Procedures Gas Wholesale Market Gas Load Curtailment and Gas Rationing and Recovery Guidelines SLIDE 256

257 AEMO S RESPONSIBILITIES & POWERS Wholesale Market System Security Procedures Response to a Threat 1) Market Response 2) Out of merit order gas at next schedule 3) Publish Ad-Hoc Operating schedule 4) Issue Direction to inject or withdraw 5) Curtailment SLIDE 257

258 IDEAL BOD LINEPACK BALANCE Max (80) 25 % Max (90) 25 % 50 TJ Min (0) Max (140) 50 % 50 TJ Min (0) 100 TJ Min (0) SLIDE 258

259 LINEPACK BALANCE MIDDLE OF EVENING PEAK ON A HIGH DEMAND DAY Max (80) 50 % Max (90) 17 % 15 TJ Min (0) Max (140) 33 % 5 TJ Min (0) 10 TJ Min (0) SLIDE 259

260 PRODUCTION FACILITY OUTAGE - INSUFFICIENT SUPPLY Major production facility trip Max (80) 50 % Max (90) 17 % 15 TJ Min (0) Max (140) 33 % 5 TJ Min (0) 10 TJ Min (0) SLIDE 260

261 PIPELINE DAMAGE OR COMPRESSOR OUTAGE INABILITY TO TRANSPORT Max (90) 17 % Max (80) 50 % 15 TJ Damage to a major pipeline or Compressor trip Min (0) Max (140) 33 % 5 TJ Min (0) 10 TJ Min (0) SLIDE 261

262 SUDDEN INCREASE IN DEMAND GPG DEMAND Max (80) 50 % GPG units unforecast Max (90) 17 % 15 TJ Min (0) Max (140) 33 % 5 TJ Min (0) 10 TJ Min (0) SLIDE 262

263 SCENARIO -HIGH DEMAND WINTER DAY High demand day Moderate level GPG VNI exports PM Incident in NEM occurs Large amount of unforecast GPG How do we respond? SLIDE 263

264 GAS EMERGENCY PROTOCOL Wholesale Market System Security Procedures Response to a Threat 1) Market Response 2) Out of merit order gas at next schedule 3) Publish Ad-Hoc Operating schedule 4) Issue Direction to inject or withdraw 5) Curtailment SLIDE 264

265 MARKET RESPONSE SLIDE 265

266 OUT OF MERIT ORDER GAS NEXT SCHEDULE Run schedule after bid cut off at 5 PM Did the market respond? o Some participants may have moved injection bids to LNG meter to cover their positions, less out of merit order LNG required Re-model with new schedule o Market response insufficient o AEMO schedules LNG above the market price SLIDE 266

267 GAS EMERGENCY PROTOCOL Wholesale Market System Security Procedures Emergency Procedures Gas SLIDE 267

268 EMERGENCY PROCEDURES GAS GAS EMERGENCY LEVELS Site based Operations incident Note: Threat to System Security may be declared at any level SLIDE 268

269 COMMUNICATIONS - RESPONSE STRUCTURE DWGM On Call & Gas Duty Manager Market System Wide Notices NEM Control Room AEMO Control Room SLIDE 269

270 OUT OF MERIT ORDER GAS NEXT SCHEDULE Schedule commences at 6PM Additional market called gas Some operational response LNG injected Pressures start to recover SLIDE 270

271 SUPPLY REDUCTION One of the plants at a major production facility trips PM High GPG and reduced supply Now what? Run a model! SLIDE 271

272 AD-HOC Modelling indicates that additional LNG is required from 7pm. The next schedule isn t until 10pm Ad-Hoc schedule is required with additional LNG schedule from 7pm. SLIDE 272

273 GAS EMERGENCY PROTOCOL Wholesale Market System Security Procedures Response to a Threat 1) Market Response 2) Out of merit order gas at next schedule 3) Publish Ad-Hoc Operating schedule 4) Issue Direction to inject or withdraw 5) Curtailment SLIDE 273

274 EMERGENCY PROCEDURES GAS GAS EMERGENCY LEVELS Operational and management Incident Management Team response teams Single Participant Operational response team Incident Response Team Single Participant Site based Operations incident SLIDE 274

275 EMERGENCY PROCEDURES GAS MANAGEMENT STRUCTURES AEMO Incident Incident Response Site Based Management Team Structure Board Incident Crisis Management Team Incident Coordinator As required Admin, Corporate Services, Finance, Facilities, Legal and P&C Emergency Management duty manage Vic Responsible officer NEM Responsible Officer Gas Real Time Operations Markets IT Duty Manager Support Hub WA Duty Manager SLIDE 275

276 COMMUNICATIONS - RESPONSE STRUCTURE VEECP ESV DELWP EMV Industry Emergency Services AEMO Incident Management Team Market Facility Control Room System Wide Notices AEMO Control Room Gas DM informed EM Team Informed Review triggers VEECP activated Y/N Participants informed SLIDE 276

277 AD-HOC Additional injections & LNG injected from 7pm The next schedule isn t until 10pm so an Ad-Hoc schedule is run, with additional LNG schedule from 7pm This additional LNG begins to stabilise the pressure SLIDE 277

278 SCENARIO CONTINUED Additional LNG from 7PM PM Pressures look okay At 7:15 PM the entire plant trips, not returning for 3 days. SLIDE 278

279 AEMO S RESPONSIBILITIES & POWERS Section 53, National Gas (Victoria) Act 2008 Wholesale Market System Security Procedures Response to a Threat 1) Market Response 2) Out of merit order gas at next schedule 3) Publish Ad-Hoc Operating schedule 4) Issue Direction to inject or withdraw 5) Curtailment SLIDE 279

280 EMERGENCY PROCEDURES GAS GAS EMERGENCY LEVELS System wide threat, public safety issue or powers Crisis invoked Management by AEMO, TeamESV or Governor in Council Crisis Management Team / Incident Management Team Impacts multiple industry participants Operational and management Incident Management Team response teams Single Participant Operational response team Incident Response Team Single Participant Site based Operations incident Note: Threat to System Security may be declared at any level SLIDE 280

281 EXAMPLE - RESPONSE STRUCTURE GEMG / EIRC NGERAC VEECP ESV DELWP EMV Industry Emergency Services AEMO Incident Management Team Facility Control Room AEMO Control Room Gas DM informed EM Team Informed Review triggers VEECP activated Y/N Participants informed SLIDE 281

282 CURTAILMENT Modelling indicates a response is required before 8pm Immediate response, not time for Ad-Hoc schedule Supply capacity isn t sufficient to meet demand A demand side response is required SLIDE 282

283 ISSUE DIRECTIONS NGR 343 (1) SLIDE 283

284 DIRECTIONS & CURTAILMENT AEMO issues direction to injectors Level of demand reduction that is required determined through modelling Curtailment tables determine which gas users are curtailed SLIDE 284

285 CURTAILMENT, GAS RATIONING & RECOVERY GUIDLINES Table 0 Unauthorised loads Table 1 Significant sites (GPG, Storage, Controllable) Table 2 MDQ > 5,000 GJ - Partial Table 3 MDQ 1,000-5,000 GJ - Partial Large Table 4 Table 5 MDQ > 5,000 GJ - Full MDQ Authorised 1,000-5,000 Sites (by GJ size) - Full Table 6 MDQ 500-1,000 GJ - Full Table 7 MDQ GJ - Full Table 8 MDQ < 250 GJ - Full Table 9 Large sites with exemptions Small Table 10 Small gas sites (Heating and Balance of load) Priority Table 11 Priority gas sites (Critical and Essential Services) SLIDE 285

286 DECLINING TARIFF D LOAD SLIDE 286

287 VOLUNTARY CURTAILMENT Reducing Industrial Load o Reduced Impact of Table 0 Table 9 curtailment High Residential Load in Winter o Potential for quick response from public voluntary curtailment SLIDE 287