report to ashurst and hall & willcox 25 september … · 9/25/2020 · the nsw land and...

REPORT TO

ASHURST AND HALL & WILLCOX

25 SEPTEMBER 2020

GAS IMPORT JETTY AND PIPELINE PROJECT

EXPERT WITNESS STATEMENT BY JEROME FAHRER

ACIL ALLEN CONSULTING PTY LTD

ABN 68 102 652 148

LEVEL NINE

60 COLLINS STREET

MELBOURNE VIC 3000

AUSTRALIA

T+61 3 8650 6000

LEVEL NINE

50 PITT STREET

SYDNEY NSW 2000

AUSTRALIA

T+61 2 8272 5100

LEVEL FIFTEEN

127 CREEK STREET

BRISBANE QLD 4000

AUSTRALIA

T+61 7 3009 8700

LEVEL SIX

54 MARCUS CLARKE STREET

CANBERRA ACT 2601

AUSTRALIA

T+61 2 6103 8200

LEVEL TWELVE

28 THE ESPLANADE

PERTH WA 6000

AUSTRALIA

T+61 8 9449 9600

167 FLINDERS STREET

ADELAIDE SA 5000

AUSTRALIA

T +61 8 8122 4965

ACILALLEN.COM.AU

RELIANCE AND DISCLAIMER THE PROFESSIONAL ANALYSIS AND ADVICE IN THIS REPORT HAS BEEN PREPARED BY ACIL ALLEN CONSULTING FOR

THE EXCLUSIVE USE OF THE PARTY OR PARTIES TO WHOM IT IS ADDRESSED (THE ADDRESSEE) AND FOR THE PURPOSES SPECIFIED IN IT. THIS

REPORT IS SUPPLIED IN GOOD FAITH AND REFLECTS THE KNOWLEDGE, EXPERTISE AND EXPERIENCE OF THE CONSULTANTS INVOLVED. THE

REPORT MUST NOT BE PUBLISHED, QUOTED OR DISSEMINATED TO ANY OTHER PARTY WITHOUT ACIL ALLEN CONSULTING’S PRIOR WRITTEN

CONSENT. ACIL ALLEN CONSULTING ACCEPTS NO RESPONSIBILITY WHATSOEVER FOR ANY LOSS OCCASIONED BY ANY PERSON ACTING OR

REFRAINING FROM ACTION AS A RESULT OF RELIANCE ON THE REPORT, OTHER THAN THE ADDRESSEE.

IN CONDUCTING THE ANALYSIS IN THIS REPORT ACIL ALLEN CONSULTING HAS ENDEAVOURED TO USE WHAT IT CONSIDERS IS THE BEST

INFORMATION AVAILABLE AT THE DATE OF PUBLICATION, INCLUDING INFORMATION SUPPLIED BY THE ADDRESSEE. ACIL ALLEN CONSULTING HAS

RELIED UPON THE INFORMATION PROVIDED BY THE ADDRESSEE AND HAS NOT SOUGHT TO VERIFY THE ACCURACY OF THE INFORMATION

SUPPLIED. UNLESS STATED OTHERWISE, ACIL ALLEN CONSULTING DOES NOT WARRANT THE ACCURACY OF ANY FORECAST OR PROJECTION IN

THE REPORT. ALTHOUGH ACIL ALLEN CONSULTING EXERCISES REASONABLE CARE WHEN MAKING FORECASTS OR PROJECTIONS, FACTORS IN

THE PROCESS, SUCH AS FUTURE MARKET BEHAVIOUR, ARE INHERENTLY UNCERTAIN AND CANNOT BE FORECAST OR PROJECTED RELIABLY.

ACIL ALLEN CONSULTING SHALL NOT BE LIABLE IN RESPECT OF ANY CLAIM ARISING OUT OF THE FAILURE OF A CLIENT INVESTMENT TO PERFORM

TO THE ADVANTAGE OF THE CLIENT OR TO THE ADVANTAGE OF THE CLIENT TO THE DEGREE SUGGESTED OR ASSUMED IN ANY ADVICE OR

FORECAST GIVEN BY ACIL ALLEN CONSULTING.

© ACIL ALLEN CONSULTING 2020

C O N T E N T S

GLOSSARY I

1

INTRODUCTION 1

2

THE RATIONALE FOR THE PROJECT 4

3

ECONOMIC BENEFITS OF THE PROJECT 12

A

JEROME FAHRER CURRICULUM VITAE A–1

B

LETTER OF ENGAGEMENT B-1

C MODELLING REPORT C-1

GAS IMPORT JETTY AND PIPELINE PROJECT EXPERT WITNESS STATEMENT BY JEROME FAHRER

i

G L O S S A R Y

GLOSSARY

Term Definition

GJ gigajoule

PJ petajoule

TJ terajoule

FSRU Floating Storage Regasification Unit

LNG Liquefied Natural Gas


1

1 I N T R O D U C T I O N

1 introduction

1. This report has been prepared by Jerome Fahrer, Director of ACIL Allen Consulting in relation to the proposed Crib Point Gas Import Jetty and Pipeline Project (Project).

2. My address is Level 9, 60 Collins Street, Melbourne, Victoria, 3000.

3. I have been engaged by Ashurst and Hall & Wallcox, on behalf of AGL Wholesale Gas Ltd (AGL) and APA Transmission Pty Ltd (APA) to provide an expert report in relation to submissions to the Crib Point Gas Import Jetty and Crib Point-Pakenham Gas Pipeline Inquiry and Advisory Committee (IAC), on the economics of the Project.

4. Ashurst and Hall & Willcox have provided me with a letter of engagement which I have read. It is annexed at Attachment B of this report.

5. I have had no previous involvement in the preparation of materials in support of the proposed Project.

6. I am an economist with nearly 40 years of professional experience, firstly at the Reserve Bank of Australia (RBA) (1982-1994), where I led the RBA’s macroeconomic research, and since 1995 at ACIL Allen Consulting (previously Allen Consulting Group). I have led around 500 major economic consulting projects, with a particular focus on economic evaluation, economic impact, competition and regulation.

7. I have undertaken numerous economics expert witness assignments on a variety of subjects. These are set out in my CV.

8. Of particular relevance to this report, I have four times previously been an economics expert witness in cases involving resource projects:

a. Olive Downs Coking Coal Mine Project – Mining Objection Hearing Pembroke Olive Downs Pty Ltd v Sunland Cattle Co Pty Ltd & Ors (MRA599-19, MRA600-19, MRA601-19, MRA602-19 & MRA603-19) (2019, 2020)

b. New Hope Coal in proceedings in the Land Court of Queensland related to the New Acland Stage 3 coal mine in Queensland MRA495-15, EPA496-15, MRA497-15 (2016)

c. Adani Mining Pty Ltd in relation to the proceedings in the Land Court of Queensland Court (Carmichael coal mine) no. MRA428-14, EPA429-14, MRA430-14, EPA431-14, MRA432-14 and EPA433-01 (2014, 2015)

d. Ashton Coal in relation to the proceedings commenced by Hunter Environment Lobby Inc in the NSW Land and Environment Court Matter (coal mine at Camberwell) No. 11154 of 2012 (2013).

9. Annexed at Attachment A is my curriculum vitae.

10. Annexed at Attachment C is a report by Owen Kelp on modelling the Victorian gas market which I requested to assist me to make an informed assessment of the economics of the Project.


2

11. In preparing this report, I have relied upon the following materials, in addition to the submissions to the IAC, which are listed in the order to which they are first referred:

a. GIJPP EES Chapter 2 Project Rationale

b. AEMO, Gas Statement of Opportunities (2020)

c. AEMO, Victorian Gas Planning Report March 2020

d. ACIL Allen Consulting, Chemical Industry Economic Contribution Analysis 2017-2018

e. Modelling report by Owen Kelp

f. ACCC, Gas Inquiry 2017-2025, Interim Report July 2020

g. ACIL Allen Consulting, Multiple Impacts of Household Energy Efficiency: An Assessment Framework

h. Bianca Peters and Stephanie F. McWhinnie “On the rebound: estimating direct rebound effects for Australian households:, The Australian Journal of Agricultural and Resource Economics, 62(1), pages 65-82, January 2018

i. Victorian Energy Upgrades, https://www.victorianenergysaver.vic.gov.au/__data/assets/pdf_file/0022/332194/VEU-Residential.pdf.

j. Opennem, https://opennem.org.au/energy/vic1/

k. Sydney Morning Herald, https://www.smh.com.au/politics/federal/the-decades-old-energy-plan-suddenly-back-in-vogue-20180425-p4zbmx.html

l. ACIL Allen Consulting, West-East Pipeline Pre-Feasibility Study, 2018

m. Energy Quest, Energy Quarterly December 2019

n. Energy Magazine, https://www.energymagazine.com.au/nsw-fast-tracks-port-kembla-gas-terminal/

12. In summary, my opinion as set out in this report is

a. The supplies of gas that Victoria has relied on for 50 years which have come from the Bass Strait fields are running down and will need to be replaced, given projected Victorian consumption of gas.

b. The Project will be able to replace these supplies, in two important respects

i. By securely contributing to the total amount of gas consumed by Victoria each year until 2040

ii. By securely contributing to peak demand in winter, when consumption of gas is around three times what it is in summer.

c. While hypothetically the gas from the Bass Strait fields could come from Queensland, this is not a practical solution, as this gas is largely contracted for export and constrained pipeline capacity limits the ability to transport it to Victoria.

d. Hypothetical replacement of the Bass Strait gas from the proposed import terminal at Port Kembla in NSW is not properly considered an alternative to the Project, because

i. this terminal might not go ahead

ii. even under proposed improvements to the Eastern Gas Pipeline that would transport this gas, it will onlt be able to make a relatively small contribution to securing peak winter supplies.

e. The argument that is made in submissions, that the emerging gap between Vicorian demand and supply can be closed by reducing demand through energy efficiency

https://opennem.org.au/energy/vic1/

https://www.smh.com.au/politics/federal/the-decades-old-energy-plan-suddenly-back-in-vogue-20180425-p4zbmx.html

https://www.smh.com.au/politics/federal/the-decades-old-energy-plan-suddenly-back-in-vogue-20180425-p4zbmx.html


3

initiatives is unconvincing, in particular because energy efficiency initiatives are already incorporated in forecasts of demand.

f. Victorian gas prices will be on average $1.09/GJ lower over the period 2020-2040 with the Project, compared to what they would be if the gas is supplied from other sources.

g. The benefit to Victorian users of gas of this lower price is in the range $2.3 billion to $3.1 billion.

h. Victorian manufacturing businesses, and in particular those in the chemistry industry, are intensive users of gas and will benefit significantly from secure and relatively inexpensive gas.

i. The Project will also benefit gas users by making the markets for the wholesaling and transport of gas more competitive. Among other benefits, this will enhance security of supply.

13. I have made all the inquiries that I believe are desirable and appropriate and no matters of significance which I regard as relevant have to my knowledge been withheld from the Inquiry and Advisory Committee.


4

2 T H E R A T I O N A L E F O R T H E P R O J E C T

2 the rationale for the Project

14. Chapter 2 of Environmental Impact Statement (EES) for the Project, “Project Rationale” sets out the reasons that AGL and APA are pursuing the Project. In this chapter of my report I review the robustness of the arguments made in this chapter. This review includes discussion of the arguments against the Project made in submissions.

Chapter 2 of the EES, Project Rationale

15. The rationale for the Project, as set out in Chapter 2 of the EES, is as follows:

a. The Bass Strait fields have supplied gas to Victoria for over 50 years, but that supply is running out.

i. The EES quotes the Australian Energy Market Operator’s (AEMO) Gas Statement of Opportunities (2020): “Several gas fields are forecast to cease

production sometime between mid-2023 and mid-2024. If production ceases earlier, this

could create peak winter day supply gaps in Victoria in 2023. Southern supply from existing

and committed gas developments will reduce by more than 35% (163 petajoules [PJ]) over

the next five years, despite an increase in committed gas developments in the past year.

Unless additional southern supply sources are developed, LNG import terminals are

progressed, or pipeline limitations are addressed, gas supply restrictions and curtailment of

gas-powered generation (GPG) for the National Electricity Market (NEM) may be necessary

on peak winter days in southern states from 2024.”.

b. Therefore, Victoria, whose economy is highly dependent on gas and whose households use gas for central heating and other uses, needs to find alternative sources of supply.

c. While there appears to be abundant supplies of gas in Queensland, the bulk of them are committed for export, and constrained pipeline capacity limits the ability to transport the gas to Victoria.

d. Similarly, while there appears to be abundant supplies of gas in Western Australia, there are no pipelines to transport it to the east.1

e. While anticipated new gas fields in Victoria could improve resource adequacy in the short term, because of pipeline constraints, they would not be generally effective in addressing peak winter day supply gaps.2

f. In a similar vein, AEMO’s Victorian Gas Planning Report March 2020, is quoted in the EES: Committed annual gas supply forecasts provided to AEMO by Victorian gas

1 See paragraphs 45 and 46. 2 Victoria’s gas demand is highly seasonal, with the demand in winter around three times that of summer.


5

producers have increased by approximately 10% for 2020-23 compared to the 2019 VGPR,

due to some anticipated projects progressing into committed projects. Despite the near-term

increase in forecasts, committed supply is forecast to reduce by 37% from 2022 to 2024 due

to field decline. Without additional gas supply, removal of pipeline constraints, or a liquefied

natural gas (LNG) import terminal, gas supply restrictions and curtailment may be necessary

from 2024. While the peak day supply forecasts provided to AEMO by gas producers have

increased slightly for 2022 and 2023 since the publication of the 2019 VGPR, there is a

significant reduction in 2024 due to a key Gippsland gas field and several smaller gas fields

being forecast to cease production sometime between mid-2023 and mid-2024… Resolving

forecast peak day shortfalls will require the progression of potential projects (currently not

considered likely to proceed during the outlook period), the expansion of pipelines for

importing additional gas supply, or an LNG import terminal. (emphasis added)

g. It is well known that once LNG exports from Queensland commenced in 2015, there followed a very sharp rise in domestic gas prices, from about $4/GJ to around $8/GJ, the latter of which reflected the world spot price. Thereafter, gas prices rose even further, to $10/GJ and higher for some buyers. (They have fallen this year due to the COVID-19 pandemic.). The EES argues that additional sources of supply are needed to bring prices down. The figure below shows gas prices from 2014-2018.3

Gas Prices 2014-2018

h. The Project will add what the EES calls liquidity but is really more competition for wholesale gas and its transport; security and reliability, which also comes from more competition; and capacity and flexibility, again the result of more competition.

i. Finally, the EES shows that it is more cost effective to convert LNG to gas at Crib Point than to transport gas via pipeline from Queensland, given the transport costs of $2.98/GJ.

Modelling by Owen Kelp

16. As a check on the analysis in the EES, I now discuss modelling of the Australian gas market done by Mr Owen Kelp.4

17. I requested the modelling to give me additional insight into the Victorian gas market, for the purposes of assessing the rationale for the Project given in Chapter 2 of the EES.

18. The modelling is not designed to determine whether the Project is needed, or whether an alternative facility or source of gas would be superior to the Project.

19. Because it uses a different methodology this modelling provides an independent check of the analysis and projections done by AEMO and others, which are cited in the EES.

20. Mr Kelp’s report explains the workings of the model. In what follows I discuss the modelling results.

3 The figure comes from a report done in 2019 by ACIL Allen for Chemistry Australia, Chemical Industry Economic Contribution Analysis 2017-2018, https://www.chemistryaustralia.org.au/news-events/chemisty_industry_launches_new_report 4 Mr. Kelp is my colleague, based in ACIL Allen’s Brisbane office.


6

21. Consistent with the EES, the modelling projects a steady decline in Victorian gas production from 344 PJ in 2020 to 111 PJ in 2040, absent the Project.5 The major decline will be from the GBJV field, from 275 PJ in 2020 to 58 PJ in 2040.

22. With the Project, however, the decline is greatly attenuated, with total Victorian production of 210 PJ in 2040 (including 98 PJ from the Project).

23. Gas consumption (demand) in Victoria is projected to fall from 213 PJ in 2020 to 184 PJ in 2040 with the Project, and to 154 PJ without it. The fall in consumption is lessened with the Project (by 29 PJ) because with the Project gas prices will be lower than they would be without it. With lower prices comes higher demand.

24. On average over the period 2020 to 2040, Victoria will consume 202 PJ of gas per year with Project and 187 PJ of gas per year without it.

25. Without the Project, Victoria will need to increasingly import gas from Queensland to meet consumption needs. The cost of transporting this interstate gas will be reflected in prices paid by Victorians. Mr Kelp’s modelling shows that the gap between the price of gas in Victoria with and without the Project increases over time. In 20306 the price of gas will be $0.98/GJ higher without the Project. In 2040 it will be $2.51/GJ higher.

26. On average over the period 2020 to 2040, prices will be lower by $1.09/GJ (in real 2020 prices) with the Project than they will be without it.

27. I conclude that the modelling is consistent with, and supports the analysis in Chapter 2 of the EES

a. Victorian-produced supplies of gas will decline over time

b. If these supplies are replaced by the Project, rather than by pipeline from Queensland, this will result in lower prices paid by Victorian consumers of gas.

ACCC

28. The ACCC is conducting a long running inquiry (2017 to 2025) into the supply of and demand for wholesale gas in Australia. The inquiry was motivated by the rapid rise in gas prices which began in 2015. In a series of reports, it has found that the wholesale gas market and market for gas transmission to be characterised by prices that are higher than would exist if these markets were competitive; that is, the ACCC has found that incumbent suppliers in these markets have exercised market power to the detriment of consumers.

29. In its latest Interim Report (July 2020)7, the ACCC says at page 14 under the heading Policy Challenges and Recommendations

“As we identified in our January 2020 report, the southern states risk facing a shortfall in the

medium term unless:

• more production and development occurs in the south to compensate for declining

production in the Gippsland Basin

• more investment occurs in north-south transportation infrastructure and/or

• one or more import terminals are developed.”

30. The ACCC’s recommendations do not just involve adding to the supply of gas in order to lower prices. They involve making the wholesale markets for gas and gas transportation more competitive.

31. The Project is consistent with the ACCC’s recommendations. AGL will be entering the wholesale market for gas. While AGL will be supplying the gas to itself for sale to residential, commercial and industrial customers, this will add to competition in the wholesale market for gas and to the market for gas transmission services, because it will be less dependent on incumbents in these markets which, according to the ACCC, are exploiting their market power and setting high prices.

5 Figure 2.6 of Mr. Kelp’s report. 6 In the base case where the cost of importing LNG is $A9.50/GJ 7 ACCC, Gas Inquiry 2017-2025, Interim Report July 2020.


7

Environment Victoria

32. In a long submission opposing the Project, Environment Victoria’s main argument on the Project’s economics is that the rationale set out in Chapter 2 of the EES is misconceived, because the prospective excess of gas demand over supply in Victoria should be resolved not by increasing supply (from the Project or other means) but by reducing demand.

33. In support of this argument, Environment Victoria sets out analysis of potential reductions in gas demand that can be achieved by energy efficiency measures, which come from a report it commissioned in 2019 by energy efficiency specialists Northmore Gordon.8

34. According to this report, Victoria could reduce its consumption of gas by 98 PJ to 113 PJ by 2030 through such measures as replacing ageing ducted gas heating systems (48 PJ), improving home building insulation (more than 10 PJ), heat pump hot water (10 PJ), and use of existing air conditioners for space heating (5 PJ to 15 PJ) and many others.

35. Environment Victoria says that consumers could be incentivised to switch to more energy efficient appliances and equipment with “targeted economic support”.

36. There are several problems with this analysis:

a. AEMO, every year in its Gas Statement of Opportunities, already considers energy efficiency measures and fuel switching in forecasting the demand for gas. The reductions in gas demand from potential energy efficiency relied upon by Environment Victoria to make its case therefore amount to double counting.

b. The Northmore Gordon analysis is one of technological opportunities. While interesting in itself, what drives consumer behaviour is changes in the cost of using their appliances and equipment. Environment Victoria says that a co-benefit of these energy efficiency measures is that consumer (and industry) costs will fall. This puts the analysis backwards. The most promising way to seriously analyse the potential for efficiency improvements to reduce the demand for gas is to (a) estimate how much these improvements will reduce prices that consumers pay for installing and using appliances and equipment and then (b) estimate what the consumer responsiveness to these price changes is, and over what time frame. It is notable that AEMO does consider price responses as a driver of consumer behaviour in forecasting gas consumption.

c. Environment Victoria appears to overestimate the willingness and/or ability of consumers to switch to more energy efficient appliances and equipment. For example, it says that it is “easy” for consumers to replace ageing ducted heating systems. But that does not mean that consumers will go to the expense of replacing a ducted heating system that is still working. Even if the running costs of a new system are lower, consumers may be constrained by the up-front capital cost of installing a new system.

37. Environment Victoria also takes no account of the rebound effect, which was described in a recent report by ACIL Allen for Energy Consumers Association as:

“Energy savings from implemented energy efficiency measures may not materialise. This is referred to as the

rebound effect and may take three forms: a) the take-back effect, where energy users increase their

consumption of energy using services (e.g. heating) b) the spending effect, where energy users spend financial

savings from energy efficiency on other energy consuming activities c) the investment effect, where investment

in energy efficiency leads to an indirect increase in economic activity and energy consumption. The rebound

effect should be considered in assessing the net impacts of energy efficiency interventions.”9

8 Many submissions (too many to list) make the same point, in identical terms: “The EES submitted by AGL grossly underestimates the potential for reducing our demand for gas in Victoria and completely ignores the desire for fuel switching and money saving to consumers of an all-electric gas free home. Victoria could reduce its gas consumption by between 98 and 113 petajoules by 2030 through using existing technology and targeted economic support according to a recent report written by energy consultants Northmore Gordon. With the right government policies Victoria could meet its energy needs without new gas including new gas fields or gas import terminals like that proposed by AGL for Westernport Bay”. 9 ACIL Allen Consulting, Multiple Impacts of Household Energy Efficiency: An Assessment Framework, report to Energy Consumers Australia, 25 October 2017, https://energyconsumersaustralia.com.au/wp-content/uploads/Multiple-Impacts-of-Energy-Efficiency-An-Assessment-Framework.pdf


8

38. The rebound effect has been found to be important in practice. A recent academic study found:

“Reducing dependence on fossil fuels by decreasing energy consumption is a common environmental policy.

One mechanism used to achieve this is to encourage increased energy efficiency. However, improving efficiency

may have an opposing effect and cause an increase in energy consumption if the intensity of use changes. This

phenomenon is known as the rebound effect. We estimate direct rebound effects for energy use in Australia

based on both aggregate residential energy use data and on household energy expenditure data. Our approach

implements a new methodology … that explicitly relates energy service use with energy source demand and

directly incorporates measures of efficiency changes. The results indicate that the rebound effect is relatively

high for energy use by Australian households. Due to the unique nature of our household data set, we can

examine the influence of demographic and housing characteristics. We find that low‐income households and

households with vulnerable members have the largest rebound effects. The relatively large rebound effects

found here suggest that consumers gain from efficiency by improved energy services, and thus, policy targeting

energy efficiency is not likely to be successful at reducing energy consumption.”10

39. As discussed above, Environment Victoria suggests that consumers receive “Targeted economic support” (i.e. subsidies) to help them switch to more energy efficient appliances and equipment. This suggestion is a long way removed from a discussion about the merits of the Project, but in any case, the Victorian Government already has a program of “targeted economic support” for exactly this purpose. Details may be found here

https://www.victorianenergysaver.vic.gov.au/__data/assets/pdf_file/0022/332194/VEU-Residential.pdf.

40. Thus, the key policy instrument which Environment Victoria says will assist to reduce the demand for gas, thereby making the Project unnecessary, is already in place. The demand for gas in Victoria that is forecast by AEMO and others already includes the effect of policies that, according to Environment Victoria, will reduce that demand. This is one of the reasons that gas demand in Victoria is forecast to fall, despite a growing population. Contrary to Environment Victoria’s submission, the scope for additional energy efficiency measures to reduce gas demand appears to be limited, certainly more limited than is made out in the submission.

41. In summary, Environment Victoria’s submits that if energy efficiency measures were adopted this would reduce the demand for gas such that the Project would not be needed. However, its submission is unconvincing, because

a. AEMO already takes account of energy efficiency on the demand for gas, and the Victorian Government already has in place policies to enhance energy efficiency.

b. It contains no analysis of how energy efficiency will affect the prices that consumers of gas will pay for appliances or their energy bills, and how long it will take them to change their appliances. It is these factors that are critical to determining their demand for gas.

c. It contains no discussion of the rebound effect of energy efficiency, which could increase the demand for energy. This is not to say that the rebound effect is definitely a problem in Victoria, but the absence of discussion by Environment Victoria is a serious omission.

Renewables

42. A recurring theme in the submissions opposing the Project is that it is inconsistent with the need to reduce gas consumption for climate change reasons, since natural gas is a greenhouse gas, and that, far from embracing additional natural gas, Victoria should move faster towards renewable sources as a means of generating electricity.

43. As far as the Project is concerned, however, this is a non-issue. Victoria uses very little gas in its electricity production. In the year to 22 September 2020, just 4.1% of Victoria’s electricity demand was

10 Bianca Peters and Stephanie F. McWhinnie “On the rebound: estimating direct rebound effects for Australian households:, The Australian Journal of Agricultural and Resource Economics, 62(1), pages 65-82, January 2018, https://onlinelibrary.wiley.com/doi/full/10.1111/1467-8489.12230?casa_token=30uI6o_I9d0AAAAA%3AsbmJT4HsVmrUXxJ0I03qr6kvFveFGaXA0dtxmd3zYc6CEJVmA9Kfp4dZkmub3cTIh0bdZuKjrYhqbg

https://www.victorianenergysaver.vic.gov.au/__data/assets/pdf_file/0022/332194/VEU-Residential.pdf


9

accounted for by Victorian gas-fired generation (1893 Gwh out of 46,353 Gwh). In contrast, renewables accounted 24.2% (11,206 Gwh) of Victorian electricity generation11

44. As Mr Kelp’s report shows, renewables are increasing their share of Victorian sent-out generation, with this share projected to rise to 50.6% in 2030. Correspondingly, the amount of gas used in Victorian electricity generation is expected to fall. While the Project will lower the price of gas in Victoria (relative to where it would be otherwise) and therefore make gas somewhat more competitive as a fuel for electricity generation, this effect will not be material.

45. All of this said, gas will retain an important role during winter peak periods when demand for electricity is high and renewable electricity output, which is intermittent, happens to be low. This is entirely consistent with the total output of gas fired electricity generators in Victoria being small and declining over time.

West to East Pipeline

46. Some submissions raise the possibility of a pipeline from Western Australia to send some of WA’s abundant gas supplies to the east coast, for example

Whilst we don’t necessarily support a transcontinental gas pipeline, we point out that there is ample potential to

link the North, West and SE Australian gas markets by existing and proposed pipelines (sub 2679)

47. This idea has been around for nearly 50 years,12 and has always been found to be economically unviable, most recently in a 2018 report by ACIL Allen to the Department of the Environment and Energy, which found (page i)13

“A West–East Pipeline represents a technically feasible option for increasing gas supply to the Eastern States of

Australia. However, commercial and market risks present major challenges for the project. To proceed, the

project would need to secure sufficient long-term commitments on the part of both gas producers and gas

buyers to de-risk the project and make it financeable. This alignment of sellers and buyers would need to be

achieved in an environment of considerable market uncertainty. Such uncertainty is not conducive to making

long-term contractual commitments. Achieving the necessary buy-in would also need to occur despite the

potential emergence of new competitive sources of gas which are closer to the Eastern Australian market and

could present buyers with more compelling alternatives. Market modelling indicates that strong uptake of gas

delivered via the pipeline would be unlikely to occur for around ten years, and that this could be further delayed if

significant new sources of supply emerge nearer to market.

On this basis, the West–East Pipeline does not currently appear to be the best or most economical option

for dealing with the supply issues currently facing the gas market in Eastern Australia.” (emphasis

added)

Port Kembla

48. Some submissions state that Australian Industrial Energy’s proposed re-gasification unit at Port Kembla is an alternative to the Project. For example

Why does the EES not mention that the Port Kembla gas importation facility of the Australian Industrial Energy

(AIE) consortium, will be operating towards the end of next year? Does AGL believe that it is not happening? It

definitively is. The NSW Government fast tracked it. It was declared “state significant infrastructure”. (sub 3162)

49. Environment Victoria, in its submission, is also (relatively) keen on Port Kembla:

In June of this year Jemena submitted plans to the New South Wales Government to connect Port Kembla LNG

import terminal to the EGP and stated “This project is the best way of enabling new gas from Port Kembla to

reach areas of demand in Victoria and New South Wales” making clear that the parties involved in the Port

11 https://opennem.org.au/energy/vic1/ 12 https://www.smh.com.au/politics/federal/the-decades-old-energy-plan-suddenly-back-in-vogue-20180425-p4zbmx.html 13 West-East Pipeline Pre-Feasibility Study, https://acilallen.com.au/uploads/files/projects/247/ACILAllen_West-EastPipeline_2018-1546902230.pdf


10

Kembla project are confident in their capacity to supply gas to Victoria and New South Wales with the current

[sic] after solving existing constraints in the gas transmission system.

While Environment Victoria does not condone the development of any fossil fuel project such as gas import

terminals, it is important to point out that Port Kembla’s LNG import terminal has not faced a similar level of

community opposition as AGL’s project have, receiving a total of only 41 submissions during its original

application and its further modification. Further, Port Kembla LNG is not going to be developed within the

boundaries of a Ramsar Site but a heavily industrialised zone.

50. If Port Kembla goes ahead, this does not undermine the rationale for the Project. They are not one-for-one substitutes. But from Victoria’s point of view, Port Kembla is not as attractive as the Project as a source of gas supply, for the following reasons:

a. It might not happen. Just as Exxon Mobil has cancelled its planned LNG import terminal because it has not been able to sign up long term customers, the same might happen at Port Kembla. According to Energy Quest’s Energy Quarterly December 2019, p21: “To date the project has only publicly announced one sales

agreement (with Energy Australia for 15 PJ/a from January 2021). Manufacturers, the

original target for the project, appear to be holding off after the recent fall in local gas prices

and improvement in availability so the project needs to lock in other retailers and is reported

to be chasing Origin Energy. Signing up Origin is critical for the future of the project. In

addition to the original 100 PJ/a (300 TJ/d) AIE was planning to import, an incremental 40

PJ/a could be required for their proposed 850 MW firming power station.”. In its most recent

(June 2020) Energy Quarterly, Energy Quest reports (p 27) AIE has said that if customers

now commit to supply agreements, making FID possible in 2020, gas could be flowing into

NSW as early as 2022. (emphasis added)

b. The Project does not face the same hurdles, because AGL does not to need find long term customers for the Project’s gas. AGL will be using the gas itself, to supply its retail customers and wholesale customers.

c. The upgrades to the Eastern Gas Pipeline proposed by Jemena will enable the transportation of “over 200 TJ per day” from Port Kembla to the Victorian market.14 However, Victorian peak demand is around 1100 TJ per day15, and the fall in Victorian peak production capacity (in 2024) will be about 580 TJ per day.16 Port Kembla will therefore not be able to replace the shortfall in supply during the winter peak.

d. As Mr Kelp’s modelling shows, the price of gas sourced from Port Kembla will be slightly more expensive than from the Project, due to transmission costs.

Conclusion

51. The rationale for the Project set out in the EES is reasonable and plausible, for the following reasons:

a. It is undeniable that the supply of gas to Victoria from the Bass Straight region is running down.

b. Given projected demand for gas in Victoria over the next 20 years or so, new sources of supply will need to be found.

c. While theoretically gas could be supplied to Victoria from alternative sources, such as by pipeline from Queensland, the Project is economically a preferred source of supply

i. It will lead to materially lower gas prices in Victoria than the alternatives

14 https://www.energymagazine.com.au/nsw-fast-tracks-port-kembla-gas-terminal/ 15 Victoria Gas Planning Report Update March 2020, Table 3, page 8. 16 Victoria Gas Planning Report Update March 2020, Table 3, page 7


11

ii. As a new source of supply, it will provide additional security for users that gas will be available, especially on peak demand days in winter.


12

3 E C O N O M I C B E N E F I T S O F T H E P R O J E C T

3 economic benefits of the project

52. The economic benefits of the Project are

a. Lower gas prices for gas users than would occur in the absence of the Project

b. Enablement of a key input to the manufacturing sector

c. Increased competition in the wholesale market for gas in Victoria

Lower prices for gas users

53. As discussed in the previous chapter, with the Project, consumption of gas in Victoria will be on average about 15 PJ higher and prices will be on average $1.09/GJ lower than without it.

54. There are 1,000,000 GJ to a PJ so consumption will be higher each year (on average) by 15,000,000 GJ with the Project.

55. A standard measure in economic analysis of the benefit that consumers receive from lower prices is called (the increase in) consumer surplus. The increase in consumer surplus has two components: the benefit from lower prices as such, and the benefit from consuming more of the good in question, where this additional consumption is enabled by lower prices.

56. The increase in consumer surplus in each year that Victorians will receive from the Project can be calculated as: (1) the reduction in price attributable to the Project multiplied by the amount of gas that would consumed without the Project, plus (2) the reduction in price attributable to the Project multiplied by the addition in consumption attributable to the Project, multiplied by one half.

57. It is appropriate to discount the value of future increased consumer surpluses into present day dollars. The present value of all consumer surpluses from 2020 to 2040 is then the economic benefit of the Project (on this measure).

58. Using a discount rate of 2.5%, the Project has an economic benefit of $3.1 billion. With a discount rate of 5%, the Project has an economic benefit of $2.3 billion.

59. To obtain the net economic benefit of the Project, the costs of constructing, operating and maintaining the Project (the FSRU and pipeline from Crib Point to Pakenham) would need to be subtracted from the estimate of consumer surplus. Also to be subtracted would be the cost of loss of amenity to local residents and other external costs, if they exist, such as negative impacts on tourism.

60. On the other hand, there are economic benefits from the Project which are not counted in the estimation of consumer surplus. These are discussed next.


13

Benefits to Victorian manufacturing

61. The Victorian manufacturing sector produces $31 billion of output per year and at the latest count in August 2020 employed 277,000 people (down from 293,000 in February due to the COVID 19 recession).

62. Gas is used intensively in many manufacturing businesses. The Victorian commercial and industrial sectors use about half of the gas consumed in Victoria, around 100 PJ per year.

63. In this section I set out the benefits of affordable and reliable gas to chemistry manufacturing businesses, with particular reference to those that use gas as a feedstock. These businesses must use gas for this purpose. There is no scope to switch to another input.

64. The analysis comes from a report done by ACIL Allen in 2019 for Chemistry Australia, Chemical Industry Economic Contribution Analysis 2017-2018. (I was a co-author.)

65. There is a group of businesses which manufacture chemicals using natural gas as feedstock. These chemical processors convert the raw gas molecule into a range of significantly value-added intermediate and finished products which are used throughout the economy. The gas is used as a chemical feedstock in the same way that iron ore is used to make steel. The chemistry industry uses the methane (CH4) and ethane (C2H6) components to manufacture a broad range of intermediate and final products which are then used throughout the economy’s supply chain.

66. Specific examples include:

a. Methane, which is made into Ammonia, Ammonium Nitrate, Sodium Cyanide, Methanol and Peroxide. These in turn are manufactured into fertilisers, mining inputs, agricultural chemicals, water treatment chemicals, cleaners, disinfectants, and biodiesel.

b. Ammonia (produced from Methane) is an important feedstock for several industries. The most commonly used fertiliser in the world, urea, is produced from ammonia. Australian industries use 1.6 million tonnes of urea each year, and each tonne of urea requires 21 GJ of natural gas. Ammonia is also used in explosives, cleaning products, fermentation, brewing, and wine making.

c. Ethane, which is made into Ethylene, Polyethylene and Ethylene Oxide.

i. Ethylene is used as an industrial refrigerant in the LNG and other industries

ii. Polyethylene is manufactured by companies to package fresh milk for domestic use and is becoming an increasingly higher value export for regional economies. It is also manufactured into poly pipe that supplies natural gas to homes and businesses.

iii. Ethylene Oxide is used for a broad range of surfactants, glycols, and other inputs to manufacturing and other sectors.

67. Natural gas is consumed in two ways in the chemistry industry: as energy to drive processes; and as feedstock. Processing energy consumption in the chemical industry is similar to other industrial sectors – fuels are consumed to provide direct heat, steam, and electricity to drive the industry’s processes, equipment, and facilities. The use of gas to feedstock is unique to the chemistry industry.

68. Feedstock describes the use of various gas, fuels, and other materials as a material input. Akin to iron ore inputs to the iron and steel industry or alumina inputs to the aluminium industry, chemical feedstock is the source of the carbon and hydrogen used to constitute a range of chemical products. Feedstock is quantified in energy units because, before use, it is indistinguishable from the same energy products used as fuels. However, once feedstock undergoes transformation in the chemical industry, it is easier to think of it as a material, with its carbon and hydrogen atoms rearranged physically to constitute the plastics and other chemical products manufactured within the industry.

69. A key aspect of gas feedstock demand is that it is non-switchable, non-substitutable, operates within a narrow band of operational tolerances, and is energy intensive.


14

70. The chemistry industry supplies 114 of Australia’s 118 industry supply chains.

71. The gas feedstock chemical sector in 2017-18 is estimated to have made a contribution to GDP (total national output of good and services) of between $8.0 billion and $10.6 billion and contributed total employment of between 33,628 and 48,500 FTE jobs. The broader chemistry sector contributed between $27.8 billion and $37.7 billion to GDP and 155,456 to 211,821 FTE jobs.

72. Over one quarter of these contributions came from businesses in Victoria. There are around 1,700 businesses in the chemistry industry in Victoria.

73. Other than as a feedstock, chemistry industry companies use gas as a source of process heat for steam and other energy needs. For these businesses, gas can represent between 35 to 50 per cent of input costs.

74. Lower prices and more secure supplies of gas, which will result from the Project, will benefit the industry, and businesses generally that use significant amounts of gas.

Competition in gas wholesaling and transport

75. Finally, a benefit of the Project will be to introduce competition to the gas wholesaling and transportation markets. AGL is currently neither a major producer nor transporter of gas. Even though it will be supplying the gas from the Project to itself, that will add competitive pressures to these markets, because AGL will be less reliant on the incumbent wholesalers and gas transporters. The benefits of this increased competition should be passed on to household and industrial consumers.

76. As well as lower prices, enhanced competition brings benefits such as better quality of service, responsiveness to problems as they arise and flexible terms and conditions.

.


A–1

A . J E R O M E F A H R E R C U R R I C U L U M V I T A E

A Jerome Fahrer curriculum vitae

Personal

Born: 14 March 1960, Sydney Australia

Business Address: Level 9, 60 Collins Street

Melbourne

Victoria 3000

Employment

Currently

Director, ACIL Allen Consulting (until April 2013, Allen Consulting Group), January 1995 –

In this role I provide economics and public policy advice to corporates and governments in the areas of competition policy and litigation, regulation, project and industry evaluation, program evaluation and economic policy, across all industries. I have led over 500 major consulting projects (details available on request).

[email protected]

www.acilallen.com.au

Previously

Member of the Board of Directors, Alzheimer’s Australia (Victoria), April 2014 to September 2017.

The Board provided the strategic direction for the organisation, ensures internal and external accountability and supervised the overall business and compliance performance of AAV.

Member, Essential Services Commission of Victoria Appeal Panel, 2005 - 2015

Section 56 of the Essential Services Commission Act (2001) provides for an appeal panel pool to be constituted from a pool of persons appointed by the Governor in Council because of their knowledge of, or experience in, one or more of the fields of industry, commerce, economics, law or public administration. Appeal panels heard appeals of decisions made by the ESC.

Member, Tasmanian Government Expert Panel reviewing the electricity supply industry (2010-2012)

Adviser to NEMMCO on compensation for Directed Parties under the National Electricity Rules (2005 – 2009)

mailto:[email protected]

http://www.acil/


A–2

Principal Fellow (Associate Professor) Melbourne Business School, 2006-2011

Reserve Bank of Australia (January 1982 – December 1994): head of macroeconomic research

Professional Activities

Member, Law Society of Australia Competition and Consumer Committee, 2011-present

Council Member, Economic Society of Australia (Victorian Branch) 1995–98 and 2013

Honorary Treasurer, Economic Society of Australia, 1997–2000

Council Member and Vice President, Economic Society of Australia (NSW Branch) 1990-1994.

Member, American Economic Association.

Education

B.Com (Hons) UNSW, 1981, first class honours, major in economics and econometrics

MPA Princeton University, 1987

MA Princeton University 1987

PhD Princeton University 1989

Dissertation: Three Essays on Comparative Macroeconomics

Adviser: Professor Ben Bernanke

Academic Honours and Awards

Woodrow Wilson Fellowship, Princeton University, 1985–1989

Olin Foundation Research Fellowship, Princeton University, 1988

Readers Digest Prize for Excellence in Teaching, Princeton University, 1988

Brinds Ltd Prize for Best Performance in Third Year Economics, UNSW 1980

Independent expert/litigation support engagements

1. Katherine Prygodicz & Ors v Commonwealth of Australia 458 and Anor019 (Robodebt class action)

VID1252/2019 - (2020) [engaged by Gordon Legal]

2. Olive Downs Coking Coal Mine Project – Mining Objection Hearing Pembroke Olive Downs Pty Ltd v

Sunland Cattle Co Pty Ltd & Ors (MRA599-19, MRA600-19, MRA601-19, MRA602-19 & MRA603-

19) (2019, 2020) [engaged by Allens]

3. Kim McKenzie v Cash Converters International Ltd ACN 069 141 546 & Ors, Federal Court of

Australia (2018) & Sean Lynch v Cash Converters Personal Finance Pty Ltd ACN 110 275 762 &

Anor, Federal Court of Australia (2018) [engaged by Herbert Smith Freehills]

4. An owner of mining transport infrastructure on the economic implications of not maintaining its

facilities (2018)

5. Australian Government in the matter Changshu Longte Grinding Ball Co., Ltd v Parliamentary

Secretary to the Minister for Industry, Innovation and Science, Federal Court of Australia

NSD952/2017 (2018) [engaged by Australian Government Solicitor]

6. A state government on the taxation of gambling (2017)


A–3

7. New Hope Coal in proceedings in the Land Court of Queensland related to the New Acland Stage 3

coal mine in Queensland MRA495-15, EPA496-15, MRA497-15 (2016) [engaged by Clayton Utz[

8. AECOM Australia in relation to the proceedings in the Federal Court of Australia (economic

forecasts used for traffic projections for a Brisbane toll road), NSD 678 of 2012, NSD 697 of 2012

and NSD 757 of 2012 (2015) [engaged by Baker & McKenzie]

9. Adani Mining Pty Ltd in relation to the proceedings in the Land Court of Queensland Court

(Carmichael coal mine) no. MRA428-14, EPA429-14, MRA430-14, EPA431-14, MRA432-14 and

EPA433-01 (2014, 2015) [engaged by McCullough Robertson]

10. Ashton Coal in relation to the proceedings commenced by Hunter Environment Lobby Inc in the

NSW Land and Environment Court Matter (coal mine at Camberwell) No. 11154 of 2012 (2013)

[engaged by McCullough Robertson]

11. Guardian Property & Asset Management in proceedings against JLF Corporation Pty Ltd Federal

Court Proceedings VID 1019 / 2012 (2013) [engaged by Marsh & Maher]

12. A major chemicals manufacturer on the economics of the transportation and disposal of hazardous

waste (2012)

13. Betfair, in its dispute with Racing NSW on the discriminatory and protectionist characteristics of

racing fields fees (2010)

14. Sony Music and Universal Music on the economics of the digital music industry (2009)

15. AGL, in a dispute with Origin Energy on the wholesale price of natural gas (2009) [arbitration,

engaged by Allens]

16. Two large manufacturers on damages arising from the Visy Amcor packaging cartel (2007, 2008)

17. Donaldson Coal on the proposed vessel queue management system at the Port of Newcastle (2007)

18. Wilson Transformer Company on damage estimation from price fixing in the electrical transformer

industry (2006)

19. Reserve Bank of Australia (designation of EFTPOS system) (2005)

20. A large wine company on changing supply and demand conditions in the wine industry (contract

dispute) (2005)

21. NEMMCO on compensation for Directed Parties under the National Electricity Rules (2005 – 2010)

22. NEMMCO on competition in system restart ancillary services (2005)

23. NEMMCO on the structure of Participant Fees (2002, 2005, 2006)

24. Gerrard Signode on interpretation and application of ‘internationally competitive’ pricing (contract

dispute) (2005)

25. A major energy utility on the trade practices implications of the sale of the Dampier to Bunbury

Natural Gas Pipeline (2004)

26. A large gas producer on how gas prices affect electricity costs and prices (contract negotiations)

(2005)

27. A large gas producer on the competitiveness of South Australian gas in the national electricity

(contract negotiations) (2004)

28. AMP Henderson for its Airports Fund Prospectus (2001)

Publications


A–4

Academic Journals

“Broadband in Australia: Present and Future”, The Melbourne Review, Vol 2(2) November 2006

“Public Hospital Costs in Two Australian States”, (with Justin G. Fung and Ian R. Harper), Australian Economic Review, Vol.33, No.2, June 2000

“Leader or Also Ran? Australia’s Competitive Position in Asia Pacific Regional Financial Markets” (with V FitzGerald), forthcoming, Journal of Applied Finance and Investment Special Supplement, 1997

"Capital Constraints and Employment” (with John Simon), Australian Economic Review, 1st Quarter, 1995

"The Unemployment–Vacancy Relationship in Australia", (with Andrew Pease) Australian Economic Review, 4th Quarter, 1993.

"Some Tests of Competition in the Australian Housing Loan Market", (with Thomas Rohling), Australian Economic Papers, December 1994

"Financial Deregulation and the Monetary Transmission Mechanism", (with Thomas Rohling), Australian Economic Review, 1st quarter, 1992, reprinted in Peter Stemp and Judith Milne–Pott (ed), Australian Readings in Monetary and Financial Economics., Longman, Melbourne, 1996.

Books and Conference Volumes

"International Trade and the Australian labour market", (with Andrew Pease) in P Lowe and J Dwyer (eds), The International Integration of the Australian Economy, Reserve Bank of Australia, 1994

"Major Influences on the Australian Dollar Exchange Rate", (with Adrian Blundell–Wignall and Alexandra Heath), in a Blundell–Wignall (ed), The Exchange Rate, International Trade and the Balance of Payments, Reserve Bank of Australia, 1993

"Is Pitchford Right? Current Account Adjustment, Exchange Rate Dynamics and Macroeconomic Policy” in M Johnson, P Kriesler and A Owen, (eds) Contemporary Issues in Australian Economics, MacMillan, Melbourne, 1991

"Some Macroeconomic Implications of Wage Indexation: A Survey", published in V E Argy and J W Nevile (eds) Inflation and Unemployment: Theory, Experience and Policy Making, George Allen and Unwin, London, 1985 (with J Carmichael and J Hawkins)

Reserve Bank of Australia Research Discussion Papers

"Wage dispersion and Labour Market Institutions: A Cross–Country Study", June 1994, (with Michael Coelli and Holly Lindsay)

"Capital constraints and Employment", June 1994, (with John Simon)

"The Unemployment–Vacancy Relationship in Australia", (with Andrew Pease) June 1993,

"The Evolution of Employment and Unemployment in Australia", (with Alexandra Heath), December 1992

"Indicators of Inflationary Pressure", (with Michael Coelli),July 1992

"Some Tests of Competition in the Australian Housing Loan Market", (with Thomas Rohling), February 1992

"Inflation in Australia: Causes, Inertia and Policy ", (with Justin Myatt), July 1991

"An Empirical Model of Australian Interest Rates, Exchange Rates and Monetary Policy (with Lynne–Ellen Shori), November 1990

"Financial Deregulation and the Monetary Transmission Mechanism", (with Thomas Rohling), November 1990.

"Wage Contracts, Sticky Prices and Exchange Rate Volatility: Evidence from Nine Industrial Countries", November 1990

"Is Pitchford Right? Current Account Adjustment, Exchange Rate Dynamics and Macroeconomic Policy", May 1990

"Optimal Wage Indexation, Monetary Policy and the Exchange Rate Regime", December 1989


A–5

"Modelling Recent Developments in Australian Asset Markets: Some Preliminary Results", (with R Rankin), August 1984

"The Equations of the RBA82 Model of the Australian Economy", (with R Rankin and J Taylor), August 1984

Book Reviews

A Wood, "North South Trade Employment and Inequality", in Agenda, Vol2(3), 1995

C DeNeubourg (ed) "The Art of Full Employment", in Economic Analysis and Policy, September 1993

R Barro, "Macroeconomic Policy", in Economic Analysis and Policy, March 1992

J Pitchford, "Australia's Foreign Debt: Myths and Realities", in Economic Papers, September 1990

Other

Various articles in the Australian Financial Review on economic policy

Referee for papers submitted to:

The Economic Record

The Australian Economic Review

Open Economies Review

The Journal of Macroeconomics

Invited Seminar Presentations

Princeton University, University of New South Wales, University of Sydney, Macquarie University, University of Melbourne, LaTrobe University, Victoria University of Wellington, Auckland University, Waikato University

Conference Presentations

5th World Econometric Congress, Barcelona, 1990; Australian Conference of Economists 1984, 1990, 1991, 1992, 1993, 1995, 1997; Australasian Meetings of the Econometric Society, 1991, 1993; Melbourne Money and Finance Conference 1996, Law Society of Australia Trade Practices Workshop 2006.


B–1

B . L E T T E R O F E N G A G E M E N T

B letter of engagement

UNDER THE ENVIRONMENT EFFECTS ACT 1978 (VIC)

PLANNING & ENVIRONMENT ACT 1987 (VIC)PIPELINES ACT 2005 (VIC)

ENVIRONMENT PROTECTION ACT 1970 (VIC)ENVIRONMENT PROTECTION AND BIODIVERSITY CONSERVATION ACT 1999

(CTH)

GAS IMPORT JETTY AND PIPELINE PROJECT INQUIRY AND ADVISORY COMMITTEE

AGL Wholesale Gas Limited and APA

Transmission Pty Ltd

Brief to Jerome Fahrer

(ACIL Allen Consulting)

Ashurst Level 26

181 William StMELBOURNE VIC 3000

T +61 3 9679 3000F +61 3 9679 3111

RWJ SCO 1000 000 480

Hall & Wilcox Level 11, Rialto South Tower 525 Collins St MELBOURNE VIC 3000 T +61 9603 3555 F +61 9670 9632

Privileged and Confidential 5 August 2020 Page 2

Gas Import Jetty and Pipeline Project

662375384.01

INSTRUCTIONS TO EXPERT WITNESS PRIVILEGED AND CONFIDENTIAL

JEROME FAHRER – ECONOMICS

1. BACKGROUND

1.1 Overview

AGL Wholesale Gas Limited (AGL) and APA Pty. Ltd. (APA) are proponents of the Crib Point Gas Import Jetty and Pipeline Project (Project) in Western Port. Ashurst acts for AGL whilst Hall & Wilcox act for APA.

The Project proposes to establish a liquefied natural gas (LNG) import jetty consisting of a floating storage and regasification unit at Crib Point Jetty and an underground bi-directional gas pipeline from Crib Point to Pakenham.

On 8 October 2018, the Victorian Minister for Planning (Minister) determined that the Project will be assessed through a single Environmental Effects Statement (EES) under Environmental Effects Act 1978 (Vic) (the EE Act).

The Commonwealth Department of Environment and Energy (DEE) has separately determined that each of the Gas Import Jetty Works (the AGL project) and the Pipeline Works (the APA project), are controlled actions under the Commonwealth Environment Protection and Biodiversity Conservation Act 1999 (Cth) (EPBC Act). These actions are to be assessed under the Bilateral Agreement between the Victorian and Commonwealth governments. Accordingly, the EES will address both the EE Act and the EPBC Act processes and requirements.

The Minister's "Reasons for Decision" and the Scoping Requirements for the EES are contained at Tabs 1 and 2. The DEE's determination that the Gas Import Jetty Works and the Pipeline Works are controlled actions are contained in Tabs 3 and 4 to this brief.

1.2 Key approval documents

The EES has been jointly exhibited together with the following approvals documentation:

(a) a Pipeline Licence Application under the Pipelines Act 2005 (Pipelines Act) for the Pipeline Works;

(b) a Works Approval Application under the Environment Protection Act 1970 (EP Act) for the Floating Storage and Regasification Unit (FSRU) component of the Gas Import Jetty Works; and

(c) a Planning Scheme Amendment (PSA) to the Mornington Peninsula Planning Scheme (C272), which will apply a Specific Controls Overlay and Incorporated Document to facilitate the use and development of land at Crib Point with the Gas Import Jetty Works. The PSA will also extend the Port Zone further around the jetty, and rezone some anomalous areas to Port Zone.

Together the Pipeline Licence Application, Works Approval Application and PSA make up the Key Approvals Documents.

1.3 The public hearing process

The proposed EES Schedule includes:

(a) a public exhibition period: 2 July – 26 August 2020; and



662375384.01

(b) a public hearing (the Hearing): from 12 October 2020 for six to eight weeks as required.

Public comments on the EES and the Key Approvals Documents will be invited during the public exhibition period. The Minister will appoint an Inquiry and Advisory Committee (IAC) to conduct the Hearing. The Terms of Reference for the IAC are provided at Tab 5.

Once appointed, the IAC will review the EES, the Key Approval Documents and public submissions and then convene the Hearing. The IAC will report to the Minister, and the Minister will make his assessment of the EES and make recommendations about the Key Approvals Documents to the relevant statutory decision makers.

Chris Townshend QC, Barnaby Chessell and Alex Guild of Counsel have been jointly briefed to appear for both AGL and APA at the Hearing.

2. ENGAGEMENT

You are instructed jointly by Ashurst and Hall & Wilcox on behalf of AGL and APA respectively. We will work cooperatively and common interest privilege will apply to your engagement.

2.1 Initial review

Subject to provision of an acceptable fee estimate, we would like to engage you to review EES Chapter 2 - Project Rationale and provide us with your preliminary expert assessment with respect to the economic impacts of the Project.

The EES can be accessed online here: https://gasimportprojectvictoria.com.au/environment-effects-statement#view-the-ees

Once you have had a chance to review Chapter 2 and any other relevant aspects of the background information in EES Chapters 1 and 3 to 5, we would like to arrange a meeting between yourself and Counsel.

Could you please provide us with:

(a) a fee estimate for your initial review; and

(b) your availability for a meeting with Counsel on 7 August or 10-12 August 2020.

For reference, the Expert Evidence Guide (Guide) used for Planning Panel hearings is provided in Tab 6 to this brief. Although your initial review may not form part of any expert evidence you may be engaged to prepare, we ask that you undertake your work in a manner which is consistent with the Guide.

2.2 Preparation of expert evidence

Subject to our consideration of your initial views on these matters, and to a further acceptable fee estimate being agreed, we may brief you to provide an expert evidence report, and present your evidence at the Hearing, for AGL and APA.

Once this engagement is confirmed, we request that you please:

(a) provide your analysis and opinion on the economic impacts of the Project. For your assistance section 4 of this brief identifies chapters and information which you may consider relevant for your statement;

(b) prepare an expert witness statement which addresses the matters set out in section 2.4 below;

https://gasimportprojectvictoria.com.au/environment-effects-statement#view-the-ees



662375384.01

(c) review any public submissions filed with the IAC during the public exhibition period which raise issues relevant to your witness statement1;

(d) identify any further information relevant to your assessment, which you require to complete your expert witness statement;

(e) appear as an expert witness at the Hearing of the Project (which may be held by digital medium depending upon the restrictions in place at the time);

(f) if required to do so by the IAC, attend a conclave with other experts in your field of expertise who are giving evidence in the Hearing; and

(g) if you consider necessary, attend a site visit of the areas relevant to your witness statement in advance of the Hearing.

2.3 Confirmation of engagement to prepare expert evidence

If we proceed to engage you as a witness, could you please:

(a) provide us with a fee estimate for the preparation of your expert witness statement and appearance at the Hearing; and

(b) provide us with a list of any general restrictions on your availability in October-November 2020

2.4 Preparing your expert witness statement

Could we please ask that your witness statement:

(a) considers the relevant evaluation objective in the Scoping Requirements and provides your opinion and analysis regarding the Chapters and Technical Reports relevant to your area of expertise. For your assistance section 4 of this brief identifies chapters and information which you may consider relevant for your statement;

(b) includes a section summarising the concerns raised in the public submissions that are relevant to your area of expertise and your opinion in response to those concerns;

(c) provides any recommendations you may have in relation to the mitigation measures proposed in the EES and outlined in Chapter 25 - Environmental Management Framework and the Key Approval Documents;

(d) is generally in accordance with the suggested structure provided in Annexure A of this brief, subject to any changes that in your opinion are necessary for your particular area of expertise; and

(e) addresses all of the matters required in the Guide used for Planning Panel hearings (which is included in Tab 6 to this brief).

3. THE PROJECT

The Project consists of two key sets of works:

(a) the Pipeline Works which are to be developed by APA; and

(b) the Gas Import Jetty Works which are to be developed by AGL.

1 Public Submissions will be provided electronically in due course.



662375384.01

3.2 The Pipeline Works

The Pipeline Works include:

(a) an underground gas pipeline approximately 57 kilometres long linking the Crib Point Receiving Facility at Crib Point and the VTS east of Pakenham (noting that various options were considered for the route and minor deviations may continue to arise due to negotiations with affected landowners along the route);

(b) a pigging facility at the Crib Point Receiving Facility to enable in-line inspections of the pipeline with a pipeline inspection gauge (pig);

(c) an above-ground Pakenham Delivery Facility adjacent to the Pakenham East rail depot to monitor and regulate gas;

(d) a below-ground End of Line Scraper Station (EOLSS) located at the connection point to the VTS, north of the Princes Highway in Pakenham; and

(e) two above-ground mainline valves (MLV1 and MLV2) located at different points along the pipeline alignment to enable isolation of the pipeline in an emergency.

3.3 The Gas Import Jetty Works

The Gas Import Jetty Works include:

(a) continuous mooring of an FSRU at Berth 2 of the existing Crib Point Jetty to store LNG and regasify LNG into natural gas using the onboard regasification unit;

(b) jetty infrastructure on the Crib Point Jetty including marine loading arms (MLAs) that would connect to the FSRU and gas piping, to transfer the gas from the FSRU to the Crib Point Receiving Facility;

(c) Crib Point Receiving Facility, including gas metering, odorant injection and nitrogen injection (if required to meet the standard gas quality specifications) – the Crib Point Receiving Facility would be located on land adjacent to the Crib Point Jetty.

3.4 The FSRU

An FSRU is a ship that can store LNG and which is also fitted with an onboard regasification unit that can return stored LNG into a gaseous state and then supply it into the gas network. The gas would be used as a fuel by domestic, commercial and industrial customers.

The FSRU would be capable of storing approximately 170,000 cubic metres (m3) of LNG and regasifying it using the onboard regasification unit as required to meet gas demand. Following regasification, the gas would be transferred from the FSRU to the Crib Point Receiving Facility via MLAs that would connect to gas piping mounted on the jetty. The FSRU would receive LNG from ships known as LNG carriers.

For a general introduction to the Project, you may wish to review Chapters 1-5 of the EES. Further details about the Project can be found in Chapter 5-Project Description.

3.5 Navigating the EES

This EES was prepared in accordance with the scoping requirements for this EES issued by the Minister in February 2019 and the Ministerial guidelines for assessment of environmental effects under the EE Act.

The EES addresses the potential impacts on the environment and informs an Environmental Management Framework for the Project. 17 specialist technical studies



662375384.01

were undertaken, and the findings of these studies are presented in the technical reports attached to this EES.

The structure of EES is shown below.

Outline of EES

Summary Report

EES Main Report

Volume 1:

Chapter 1. Introduction

Chapter 2. Project rationale

Chapter 3. Project development

Chapter 4. Project description

Chapter 5. Key approvals and assessment framework

Volume 2:

Chapter 6. Marine biodiversity

Chapter 7. Terrestrial and freshwater biodiversity

Chapter 8. Surface water

Chapter 9. Groundwater

Chapter 10. Contamination and acid sulfate soils

Chapter 11. Greenhouse gas

Chapter 12. Air quality

Chapter 13. Noise and vibration

Chapter 14. Landscape and visual

Chapter 15. Transport

Chapter 16. Safety, hazard and risk

Chapter 17. Land use

Chapter 18. Social

Chapter 19. Business

Chapter 20. Agriculture

Chapter 21. Aboriginal cultural heritage

Chapter 22. Historic heritage

Volume 3:

Chapter 23. Climate change risk

Chapter 24. Sustainability

Chapter 25. Environmental Management Framework

Chapter 26. Stakeholder Engagement

Chapter 27. Conclusion

Technical Reports

A. Marine biodiversity

B. Terrestrial and freshwater biodiversity

C. Surface water

D. Groundwater

E. Contamination and acid sulfate soils

F. Greenhouse gas

G. Air quality

H. Noise and vibration

I. Landscape and visual

J. Transport

K. Safety, hazard and risk

L. Land use

M. Social

N. Business

O. Agriculture

P. Aboriginal cultural heritage

Q. Historic heritage



662375384.01

Outline of EES

Attachments

I. Matters of National Environmental Significance

II. Legislation and policy report

III. Environmental risk report

IV Climate change risk report

V. Community engagement reports

VI. Draft planning scheme and amendment

VII. Map book

VIII: EPA Works approval application

IX: Pipeline licence application

4. PROJECT RATIONALE

Volume 1, Chapter 2 contains the project rationale for the Project, other background information is contained in Chapters 1 and 3 to 5. A copy of these documents are available on the Crib Point Jetty Gas Works website for the Project. We can also provide you with hard copies of these documents if required.

Please also review any other documents (in the EES or otherwise) you consider relevant to your engagement.

APA has developed an interactive mapping tool that may assist your understanding of the pipeline route, including zone and overlay controls, mapped protected species, waterways etc. If you think it would assist, we can arrange for you to be given access to this mapping tool.

5. COMMUNICATION AND CONFIDENTIALITY

Your instructing solicitors for your engagement are Sophie Osborn, Ashurst, and Meg Lee, Hall & Wilcox. Sophie Osborn is your primary contact for the Project.

In order to ensure that legal professional privilege is retained in relation to your work products, we request that you comply with the following communication and information management protocol during the course of this engagement:

(a) Written communications (including email) should be addressed to your primary contact.

(b) Written communications (including email) with AGL personnel in relation to this retainer should be addressed to Robert Jamieson, Sophie Osborn or Anna Seddon of Ashurst but may be copied to the relevant person at AGL who is involved in actioning the substance of the communications.

(a) Written communications (including email) with APA personnel in relation to this retainer should be addressed to Natalie Bannister or Meg Lee of Hall & Wilcox but may be copied to the relevant person at APA who is involved in actioning the substance of the communications.

(c) To the extent that you communicate with AGL, APA, Ashurst or Hall & Wilcox by telephone, please keep any notes of these conversations in a folder marked "Confidential and Subject to Common Interest Privilege – for Ashurst and Hall & Wilcox".

(d) This brief, any other materials, printed email, working notes or other documents relating to this retainer should also be maintained in a file clearly marked with the words: "Confidential and Subject to Common Interest Privilege – for Ashurst and Hall & Wilcox".

https://gasimportprojectvictoria.com.au/environment-effects-statement#view-the-ees



662375384.01

6. FEE PROPOSAL AND INVOICING

As set out above, we request that you provide Ashurst with a fee proposal that outlines any applicable rates and disbursements required for you to prepare your report and appear as a witness.

You should liaise directly with your primary contact in relation to the scope of work and terms of this engagement.

Invoices in relation to your services should be:

(a) addressed to Ashurst;

(b) clearly demonstrate all services undertaken; and

(c) forwarded to Anna Seddon and Sophie Osborn of Ashurst, and we will then include your fees as a disbursement on our monthly invoices to AGL and APA.

7. CONFLICTS OF INTEREST

As an independent expert, it is important that you are free from any possible conflict of interest in providing your advice which could preclude you from providing your opinion in an objective and independent manner.

Please notify us as soon as possible if you become aware of any connection you have with any other party which would preclude you from providing your opinion in an objective and independent manner.

8. ADMINISTRATIVE MATTERS

We would be grateful if you could confirm agreement to the terms of this brief, and provide your fee proposal by way of reply email.

If you have any questions, please contact Sophie Osborn on (03) 9679 3881, Meg Lee on (03) 9603 3312 or Anna Seddon on (03) 9679 3041.

Ashurst and

Hall & Wilcox

5 August 2020

ANNEXURE A

Structure for Witness Statement

1. INTRODUCTION

(a) name and address;

(b) qualifications, experience and area of expertise; [Ashurst/H&W suggestion: This may be included as an annexure if it is long].

(c) details of any other significant contributors to the statement (if there are any), and their expertise;

(d) details and qualifications of any person who carried out any tests or experiments upon which the expert has relied in preparing the statement.

2. INSTRUCTIONS AND INFORMATION RELIED UPON

(a) all instructions that define the scope of the statement (original and supplementary and whether in writing or verbal).

[Ashurst/H&W suggestion: Reference Memo of Instructions]

3. FACTS, MATTERS AND ASSUMPTIONS

(a) the facts, matters and assumptions on which the expert relies in preparing the statements;

(b) reference to documents and materials the expert has used in preparing the statement.

4. SUMMARY OF KEY ISSUES, OPINIONS AND RECOMMENDATION

5. CONSIDERATION OF CHAPTER AND EXHIBITED TECHNICAL REPORT

Consider the draft evaluation objective in the Scoping Requirements and provide your opinion and analysis on the relevant chapter and technical report in the EES.

6. REVIEW OF SUBMISSIONS

[Ashurst/H&W suggested approach]:

(a) If >5 submissions, your witness statement can respond to consistent themes/concerns raised by submitters rather than by responding to specific submitters

(b) If <= 5 submissions, your witness statement should respond to specific submitters (can cross refer to responses made to other submissions if required).

7. REVIEW AND RECOMMENDATIONS ON THE MITIGATION MEASURES IDENTIFIED IN THE EES AND THE KEY APPROVAL DOCUMENTS

As relevant to your area of expertise:

(a) review the mitigation measures recommended in the EES relevant to your area of expertise (these are discussed in the Chapter relevant to your expertise and are also identified in Chapter 25- Environmental Management Framework);

(b) review the Incorporated Document in the draft Planning Scheme Amendment;

(c) review the Pipeline Licence Application;



662375384.01

(d) review the Works Approval Application; and

(e) provide any recommendations you have regarding the proposed mitigation measures or the Key Approval Documents.

8. DECLARATION

(As per Expert Witness guide, provided as Tab 6 of this engagement brief).



662375384.01

ANNEXURE B

Index of Documents

Tab Document Date

1. EES Reasons for Decision 8 October 2018

2. EES Scoping Requirements January 2019

3. EPBC Act Controlled Action Decision – AGL 28 November 2018

4. EPBC Act Controlled Action Decision - APA 28 November 2018

5. Terms of Reference for the IAC 1 June 2020

6. Expert Evidence Guide for Planning Panel hearings April 2019


C–1

C . M O D E L L I N G R E P O R T

CC

modelling report

REPORT TO

ASHURST

25 SEPTEMBER 2020

MARKET IMPACTS OF CRIB POINT

TECHNICAL REPORT FINAL


ABN 68 102 652 148

LEVEL NINE

60 COLLINS STREET

MELBOURNE VIC 3000

AUSTRALIA

T+61 3 8650 6000

LEVEL NINE

50 PITT STREET

SYDNEY NSW 2000

AUSTRALIA

T+61 2 8272 5100

LEVEL FIFTEEN

127 CREEK STREET

BRISBANE QLD 4000

AUSTRALIA

T+61 7 3009 8700

LEVEL SIX


CANBERRA ACT 2601

AUSTRALIA

T+61 2 6103 8200

LEVEL TWELVE

28 THE ESPLANADE

PERTH WA 6000

AUSTRALIA

T+61 8 9449 9600

167 FLINDERS STREET

ADELAIDE SA 5000

AUSTRALIA

T +61 8 8122 4965

ACILALLEN.COM.AU

















MARKET IMPACTS OF CRIB POINT TECHNICAL REPORT FINAL 1


1 Introduction

Ashurst act on behalf of AGL Wholesale Gas Limited (AGL) and Hall & Wilcox act on behalf of APA Transmissions Pty Ltd (APA) who jointly propose to develop a Liquefied Natural Gas (LNG) import facility and associated gas transmission pipeline in Westernport, Victoria (the Project).

Ashurst and Hall & Wilcox have jointly engaged me to prepare an independent technical report for the purposes of the public hearing on this matter.

1.1 Report Author

Owen Kelp

Director

ACIL Allen Consulting Pty Ltd

Level 15, 127 Creek Street,

Brisbane QLD 4000

1.2 Qualifications

Graduate Diploma of Applied Finance and Investment from the Financial Services Institute of Australasia (FINSIA – 2005).

Bachelor of Business (Economics and Finance) from Queensland University of Technology – 1999

Owen Kelp is a Director of ACIL Allen Consulting with twenty years of experience specialising in electricity, gas and renewable energy markets. Owen has worked extensively on energy industry matters and across a broad range of assignments including market demand, supply and price forecasting studies; strategic reviews; transmission and distribution networks (project evaluation, throughput forecasts, asset sales and due diligence work); project evaluation (financial modelling, market studies and economic benefits) and regulatory matters.

In electricity, Owen has extensive experience undertaking various modelling projects in Australian wholesale electricity markets (NEM and WEM), including short and long-term outlooks and detailed due diligence for asset sales/acquisitions and transmission studies. Owen has undertaken a number of assignments in relation to renewable energy and environmental certificate markets including outlooks for certificate demand/supply and price outlooks in the context of renewable asset due diligence.

He has authored multi-client studies examining the prospects and impacts of renewable energy development in Australia’s electricity markets. He was also the project manager on an assignment assisting the Commonwealth Government appointed Expert Panel’s review of the Renewable Energy


Target in 2014 and the Energy Security Board in relation to the development of the National Energy Guarantee in 2018.

His energy experience also extends across the gas industry, having undertaken a range of market outlooks, demand/supply studies, commercial analysis, pipeline evaluation and due diligence activities. He has considerable experience in relation to commercial aspects of coal seam gas and conventional gas developments, as well as a good understanding of the interaction between gas and electricity markets. In the area of gas pipeline regulation, Owen has assisted a number of clients and regulators primarily relating to demand forecasts as a key input to transmission and distribution network access arrangements. This work has included methodology assessments of third-party forecasts, as well as undertaking independent forecasting studies. Owen’s detailed knowledge of the workings and outlook for the power generation sector has been key aspect of his work in this area.

1.3 Instructions and information relied upon

I have been instructed to:

a) undertake economic modelling to understand the impact of the Project, and of the Project not proceeding, on the Victorian and the East coast gas markets, including in relation to gas price, supply, and the composition of energy generation

b) prepare a technical report (Report) which sets out the assessment of the modelling referred to in (a) above.

c) identify any further information relevant to the assessment, required to complete the Report.

The information that I have relied upon includes:

— the Environment Effects Statement (EES) for the Project

— the Australian Energy Market Operator (AEMO) 2020 Gas Statement of Opportunities (GSOO) report

— the AEMO 2020 Victorian Gas Planning Report (VGPR)

— ACIL Allen’s internal Gas and Electricity Reference cases (current as at the date of this report).

1.4 This report

This report presents results from economic modelling of the Eastern Australian wholesale gas and electricity markets for the purposes of quantifying the market impacts of the Project.

The modelling draws upon ACIL Allen’s in-house gas Reference case scenario for the Australian wholesale gas market and includes a range of supply and demand assumptions drawn from various publicly available sources (such as AEMO’s 2020 Gas Statement of Opportunities report and Victorian Gas Annual Planning report) and in-house intelligence including detailed market modelling of the National Electricity Market.

As a modelling exercise, the analysis is necessarily a simplification of the real world and utilises fundamental economic concepts to make projections of the gas market’s evolution in Eastern Australia. The results are not intended to represent accurate predictions about market outcomes or utilisation of the Project as the modelling does not consider commercial factors such as ownership structures or contractual positions of individual parties.

The modelling necessarily includes a portion of as-yet undeveloped reserves and resources which are somewhat speculative. This contrasts with other planning exercises, such as the Gas Statement of Opportunities report, which typically only includes currently developed or known supply sources for the purposes of highlighting the scale and timing for new supply and transmission investment to ensure demand is met.

The Base case scenario includes the proposed AGL Crib Point LNG import terminal with up to 160 PJ/a of annual capability and daily capacity of up to 795 TJ/d. This has been run against a scenario in which the Crib Point terminal does not proceed, holding all other assumptions constant.

The gas market modelling included a number of scenarios which test a range of factors including:

— The price at which the AGL terminal can import gas from international markets


— Whether the Narrabri gas supply project proposed by Santos goes ahead in New South Wales (a key market uncertainty in the near-term)

— An alternative scenario in which the Project is not developed, but an alternative import terminal is developed at Port Kembla in NSW.

Modelling outputs include projections for:

— Wholesale gas price outcomes for Victoria

— Utilisation of the Project

— Impacts on Victorian gas consumption

— Impacts on Victorian gas production.


2 P R O J E C T E D M A R K E T I M P A C T S

2 Projected Market impacts

2.1 Gas scenarios examined

The analysis undertaken draws from ACIL Allen’s current Reference case scenario for the Eastern Australian gas market. An overview of key assumptions used in is provided in Table 2.1. Modelling was conducted using GasMark (see Appendix A for details on the model) over the period 2020 to 2040 at a monthly resolution.

TABLE 2.1 REFERENCE CASE ASSUMPTIONS

Parameter Assumption and narrative

Global – long term oil price Oil at US $65/bbl

Global – long term exchange rate A$:US$ = 0.75

LNG export price A$11.00/GJ

Gas demand – residential / commercial /

industrial

Future annual demand reflects current trends as demonstrated in the latest Gas Statement of

Opportunities Report from AEMO.

Gas demand – electricity generation GPG daily demand profiles reflect outcomes from ACIL Allen’s current Reference Case electricity

market model for the National Electricity Market. Individual custom profiles for each gas station

reflect modelled daily dispatch of that station.

Gas supply – Bass Strait region Includes new (and recently commissioned) conventional supply in the Bass Strait region including

Halladale–Blackwatch–Speculant (Otway); Kipper–Tuna–Turrum (Gippsland) and Sole

(Gippsland). Also assumes tie-in of additional gas reserves in the Bass Basin (Trefoil,

Gentoo/Rockhopper) which extends life span of the BassGas Project. Long lead time projects

such as South East Remora, Manta, La Bella in the offshore Gippsland and Otway Basins are

assumed to offer new gas supply, with capacity ramping up later in the 2020s and into the 2030s.

Gas supply – Cooper Basin Conventional gas production and deliverability capability from the Cooper Basin reflects currently

developed and committed 2P reserves and contingent resources only. Unconventional production

increases to levels around 30 PJ by year 2030.

Gas supply – Surat/Bowen basins Field developments provide sufficient supply capability to meet Gladstone LNG plant

requirements, with modest excess capacity available to support domestic deliveries. Arrow

Energy’s gas fields are modelled according to recent announcements made with LNG producers

(particularly QCLNG) and their recent FID announcement.

Gas supply - NSW Narrabri development by Santos goes ahead despite the project not receiving the required

regulatory approvals yet and no ultimate decision has been made to proceed. ACIL Allen has

introduced Narrabri into our Base Case and sets supply equivalent to its full capacity as stated by

Santos (75 PJ/a), ramping up to this level over the period 2024 to 2028.



Gas transmission pipelines Capacity of pipelines reflect current installed capacities, with expansions (if deemed commercial)

required to ensure that gas movements are not constrained by pipeline capacity over the long-

term. In this scenario, the only material new pipeline infrastructure includes that required to bring

the Narrabri Project to market.

Queensland LNG exports Liquefaction capacity at Gladstone is limited to the currently committed six trains (nominal 25.3

Mt/a LNG) with each plant operating at a level corresponding to its current LNG contract levels.

As a result, the effective output of the six trains is 22 Mt/a LNG. However, maximum capacity is

set at nameplate capacity.

LNG import terminals One LNG terminal (Crib Point) at up to 160 PJ/a capacity, delivery capability up to 795 TJ/d.

COVID-19 impact COVID-19 impacts the market over the short term (12-24 months) but the energy market begins

to recover strongly from 2021. The impacts are incorporated via adjustments to the level of LNG

exports and reduced domestic demand.

SOURCE: ACIL ALLEN GAS REFERENCE CASE JULY 2020

The only change to ACIL Allen’s standard Reference case assumptions has been to align the Crib Point import terminal capacity with that outlined with the Project EES document.

Table 2.2 details the various scenarios examined.

One of the key sensitivities is the cost at which LNG can be imported into Victoria relative to prevailing domestic prices. This will be dependent upon Asia-Pacific LNG spot prices throughout the year relative to LNG contract prices. It is likely that LNG spot cargoes would be acquired for less than annual average LNG contract prices as:

a) LNG spot prices (which are determined by market supply-demand dynamics) are generally less than long-term contract prices which have a strong oil linkage

b) cargoes could be acquired during the northern hemisphere summer when aggregate gas demand and prices are seasonally lower.

While the Base case assumes an import cost of A$9.50/GJ, the modelling has also examined a High and Low import cost sensitivity around this value.

The modelling also looks at the impact of the Narrabri gas project in NSW not proceeding as this is assumed to occur in ACIL Allen’s Reference case scenario and finally a scenario in which an alternative import terminal is developed at Port Kembla in NSW rather than Crib Point.

TABLE 2.2 GAS MARKET SCENARIOS EXAMINED

Scenario Description

Base case ACIL Allen Reference case assumptions. Crib Point import terminal

developed; assumed import cost of A$9.50/GJ

No terminal case No import terminals developed

Base case (High import cost) Crib Point import terminal developed; assumed import cost of

A$10.50/GJ

Base case (Low import cost) Crib Point import terminal developed; assumed import cost of

A$8.00/GJ

No terminal case; No Narrabri case No import terminals developed; Narrabri gas project does not proceed

No Narrabri case Crib Point import terminal developed; assumed import cost of

A$9.50/GJ; Narrabri gas project does not proceed

No Narrabri case (Low import cost) Crib Point import terminal developed; assumed import cost of


Port Kembla terminal case Crib Point import terminal not developed; Port Kembla import terminal

proceeds (import cost of A$9.50/GJ)


2.2 Price impacts

Gas market modelling suggests the impact of the Project will be to put downward pressure on Victorian prices (represented by the price of wholesale gas at the Melbourne city-gate) over the projection period.

The figure below shows the projected annual average price for wholesale gas in Melbourne under the Base case scenarios at various assumed import prices relative to a No terminal case. Supply to Victoria is under pressure by the late 2020’s due to the depletion of reserves in existing Basins. Together, with minimal investment predicted in offshore Victorian basins, gas prices rise quickly above $10/GJ (real 2020 dollars) in the 2030s and above $12/GJ by the end of the projection period.

The impact of the Project will depend to some extent on the relative cost of imports versus prevailing wholesale prices in the domestic market. The lower the import cost, the greater the utilisation of LNG imports and the more downward pressure is exerted on domestic prices. The impact on 2030 outcomes as modelled, ranges from $0.20/GJ (2%) lower under the High import cost assumption through to $1.29/GJ (13%) lower under the Low import cost assumption. By 2040, this range increases to $1.63/GJ (13%) lower and $3.40/GJ (27%), respectively.

FIGURE 2.1 PROJECTED WHOLESALE GAS PRICES FOR MELBOURNE CITY GATE (REAL 2020 $/GJ)

SOURCE: GASMARK MODELLING

The market impacts of the Project will also depend upon other gas demand and supply developments which occur over the projection period. Figure 2.2 shows the impact of the Project upon price outcomes is larger when the supply-demand balance is tighter. In these scenarios, the proposed Narrabri gas project in NSW is assumed not to proceed.1

1 Narrabri is assumed to come online around 2024 and produces 75 PJ per annum at full capacity in the preceding scenarios.

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11.00

12.00

13.00

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Rea

l 202

0 $/

GJ

No terminals Base Case (High import price) Base Case Base case (Low import price)


FIGURE 2.2 PROJECTED WHOLESALE GAS PRICES FOR MELBOURNE CITY GATE WITH NARRABRI NOT DEVELOPED, (REAL 2020 $/GJ)


2.3 LNG import terminal utilisation

Figure 2.3 shows modelled utilisation of the project under the Base case scenarios. The Base case sees annual volumes of around 40 PJ/a, increasing over time as the domestic supply-demand balance tightens and Victoria’s reliance on imported gas increases. The High and Low import price sensitivities highlight that the utilisation of the facility will be dependent on the relative LNG import prices.

FIGURE 2.3 PROJECTED CRIB POINT UTILISATION (PJ)


Initially, the Project is modelled to operate more like a ‘peaker’, adding supply to the market during peak demand periods (mainly during the winter months) when prevailing spot gas prices are high (as shown in Figure 2.4). However, its role transforms from mainly a peaker to a baseload gas supplier over the projection period due to depleting resources and higher cost supply, the terminal is called on to import year-round, not just in the winter months.

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11.00

12.00

13.00

14.00

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Rea

l 202

0 $/

GJ

No terminals; No Narrabri Base Case; No Narrabri Base case (Low import price); No Narrabri

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

PJ



FIGURE 2.4 PROJECTED CRIB POINT MONTHLY UTILISATION FOR SELECTED YEARS: BASE CASE (PJ)


As shown below, the utilisation of the facility is projected to be higher should the Narrabri gas project not proceed. In these scenarios, the Project is projected to be called on more in both the initial years and later in the projection period. The terminal is projected to become a significant source of year-round supply if Narrabri is not developed, capping out at the assumed import capacity of 160 PJ/a by the late-2030’s under the Low import cost case.

FIGURE 2.5 PROJECTED CRIB POINT UTILISATION: NO NARRABRI SENSITIVITY (PJ)


We understand that there may be a practical physical limitation on the ability of the import terminal to only operate for winter periods. Should this be the case, AGL may be required to operate the facility all year round and inject at least some gas into the Victorian grid for non-winter months.2 If this is the case, injection volumes may be higher than those shown, and the facility would be expected to have a further dampening effect on Victorian wholesale gas price outcomes.

2.4 Impacts on gas supply into Victoria

The main sources of gas supply for the south-eastern Australian market are the Gippsland, Otway and Bass Basins located principally offshore in Bass Strait. These supply sources have become

2 ACIL Allen have been informed that this could be up to 2 PJ/month.

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

PJ

2024 2030 2035 2040

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

180.0

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

PJ



increasingly important to the Eastern Australian domestic market as much of the production in Central Australia (Cooper Basin) is being directed to LNG export markets through Gladstone, rather than to domestic markets.

The Gippsland Basin contains the largest conventional gas reserves in Eastern Australia, with the majority of this controlled by the Esso/BHP Gippsland Basin Joint Venture (GBJV).3 However these legacy fields are now in decline and production is expected to steadily fall over the coming decade. Falling rates of supply are expected to be most evident in the winter months as peak day deliverability declines. Even with five processing plants in Victoria (Longford, Sole, Lang Lang (BassGas), Otway and Casino), supply is highly reliant on the Longford processing plant which accounts for more than 80 per cent of supply. Figure 2.6 shows the modelled Victorian gas production by Basin in the scenario with no import terminals.

FIGURE 2.6 PROJECTED VICTORIAN GAS SUPPLY WITH NO IMPORT TERMINAL (PJ)


This is contrasted with Figure 2.7 which shows the development of the Crib Point terminal resulting in a material level of incremental supply from Victoria. This enables Victoria to be self-sufficient for longer on an annual basis but still reliant imported gas from other States through peak winter months.

FIGURE 2.7 PROJECTED VICTORIAN GAS SUPPLY WITH CRIB POINT IMPORT TERMINAL (PJ)


Figure 2.8 shows the impact of the incremental supply from the LNG import terminal on Victorian net exports to neighbouring States. Without the terminal, net exports from Victoria decline significantly,

3 In the past, Esso/BHP jointly marketed their Gippsland Basin gas entitlements; that arrangement is now coming to an end, with the joint venture parties separately marketing their gas entitlements since January 2019.

0

50

100

150

200

250

300

350

400

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

GBJV Other Gippsland Bass Casino, Minerva, Henry Other Otway

0

50

100

150

200

250

300

350

400

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

GBJV Other Gippsland Bass Casino, Minerva, Henry Other Otway Crib Point LNG


reaching a net zero export position in the early 2030’s and becomes increasingly reliant on imports from other States (particularly NSW) through to 2040.

In contrast, the Base case which includes the Crib Point import terminal results in Victoria remaining self-sufficient throughout the projection period. The importance of the import terminal for the Eastern Australian market is even more pronounced in scenarios in which the Narrabri CSG project does not proceed.

FIGURE 2.8 PROJECTED VICTORIAN MONTHLY NET EXPORTS TO OTHER STATES: WITH AND WITHOUT CRIB POINT TERMINAL

Note: Aggregate net flow calculated as sum of monthly projected flows on SEAGas, VIC-NSW interconnect, Eastern Gas Pipeline and Tasmanian Gas Pipeline


2.5 Impacts on gas consumption

Figure 2.9 present a comparison of modelled Eastern Australian gas consumption in the Base case and No import terminal cases, along with a comparison against the AEMO 2020 GSOO demand forecast. ACIL Allen’s Base case is lower than AEMO through to 2024, with much of this driven by a reduction in gas-fired generation resulting from near-term renewable capacity coming online. The two series converge from 2026 with ACIL Allen’s electricity market modelling projecting an early staged closure of Yallourn power station at this point, with longer-term declines in consumption relating to fuel switching stemming from high gas prices.

Projected aggregate gas consumption is lower in the No Terminal case (as shown in Figure 2.10), as a result of the higher wholesale gas prices that result under this scenario. Most of these price elasticity effects occur in Victoria, although higher prices also flow through other States. Gas consumption is projected to be around 24 PJ (5%) lower in 2030, rising to 45 PJ (10%) by 2040. The figure also shows the data broken down by end user category. The demand reduction is projected to occur in

-15

-10

-5

0

5

10

15

20Ja

n-20

Oct

-20

Jul-2

1

Apr

-22

Jan-

23

Oct

-23

Jul-2

4

Apr

-25

Jan-

26

Oct

-26

Jul-2

7

Apr

-28

Jan-

29

Oct

-29

Jul-3

0

Apr

-31

Jan-

32

Oct

-32

Jul-3

3

Apr

-34

Jan-

35

Oct

-35

Jul-3

6

Apr

-37

Jan-

38

Oct

-38

Jul-3

9

Apr

-40

PJ/

mon

th

No import terminal

SEAGas EGP Interconnect TGP

-15

-10

-5

0

5

10

15

20

Jan-

20

Oct

-20

Jul-2

1

Apr

-22

Jan-

23

Oct

-23

Jul-2

4

Apr

-25

Jan-

26

Oct

-26

Jul-2

7

Apr

-28

Jan-

29

Oct

-29

Jul-3

0

Apr

-31

Jan-

32

Oct

-32

Jul-3

3

Apr

-34

Jan-

35

Oct

-35

Jul-3

6

Apr

-37

Jan-

38

Oct

-38

Jul-3

9

Apr

-40

PJ/

mon

th

Base case



industrial and commercial/residential users, with the reduction in gas-fired power generation accounting for a smaller proportion.

FIGURE 2.9 PROJECTED EASTERN AUSTRALIAN GAS CONSUMPTION WITH AND WITHOUT IMPORT TERMINAL (PJ)

Note: Eastern Australia = QLD, NSW/ACT, VIC, SA and TAS

SOURCE: GASMARK MODELLING, AEMO 2020 GAS STATEMENT OF OPPORTUNITIES

FIGURE 2.10 PROJECTED IMPACT ON EASTERN AUSTRALIAN GAS CONSUMPTION WITHOUT IMPORT TERMINAL (PJ): BY STATE AND BY END USER CATEGORY


0

100

200

300

400

500

600

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

Base case No import terminals AEMO 2020 GSOO

-50

-45

-40

-35

-30

-25

-20

-15

-10

-5

0

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

Queensland New South Wales Victoria South Australia Tasmania Australian Capital Territory

-50

-45

-40

-35

-30

-25

-20

-15

-10

-5

0

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

Power generation Industrial Commercial/Residential


Figure 2.11 presents the projected impact on aggregate gas consumption volumes in Victoria resulting from the development of the Project. Consumption volumes are around 12.2 PJ (6%) lower by 2030, with this rising to 29.3 PJ (16%) lower by 2040 in the absence of the terminal.

FIGURE 2.11 PROJECTED IMPACT ON VICTORIAN GAS CONSUMPTION WITHOUT IMPORT TERMINAL (PJ)


2.6 Port Kembla development

The final gas market scenario examined, models the impact of an alternative LNG import terminal proceeding – specifically the Port Kembla terminal proposed by Australian Industrial Energy (AIE). This scenario assumes the import terminal to be the same size as used in the Base case for Crib Point, with the only difference being the geographical location. Figure 2.12 shows the resulting price outcomes for Melbourne in comparison with the Base case scenario. Price outcomes are broadly the same through to the late 2020’s before the Port Kembla scenario rising slightly more than the Base case. This is due to Victoria initially exporting less gas in the early years to NSW under the Port Kembla case, with little impact on Victorian outcomes, but relying on imports and incremental transmission costs late in the projection period (as shown previously in Figure 2.8).

FIGURE 2.12 PROJECTED WHOLESALE MELBOURNE CITY GATE GAS PRICES WITH PORT KEMBLA LNG (REAL 2020 $/GJ)


-40.0

-35.0

-30.0

-25.0

-20.0

-15.0

-10.0

-5.0

0.0

5.0

0

50

100

150

200

250

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Cha

nge

(PJ)

PJ

Change (PJ) Base case No import terminal

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11.00

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Rea

l 202

0 $/

GJ

Base Case (Crib Point at 9.50/GJ) Port Kembla ($9.50/GJ)


Figure 2.13 compares import volumes between the two scenarios, showing that a Crib Point or Port Kembla location yield similar LNG import outcomes within the modelling.

FIGURE 2.13 COMPARISON OF PROJECTED IMPORT VOLUMES


2.7 Electricity market projections

Figure 2.14 shows projected outcomes for Victoria from ACIL Allen’s RC53 Reference case electricity market outlook, which utilises the gas prices from the Gas Base Case (i.e. with Crib Point proceeding).

Due to relatively high gas prices and low levels of price volatility projected in the near-term, gas-fired generation is projected to play a small supporting role within the generation mix. This is similar to modelling conducted by AEMO within the Victorian Gas Planning Report for 2020 which has gas-fired generation volumes falling by 75% in the near-term, with gas use declining from 20 PJ in 2019 (actual) down to 5 PJ expected for 2021.4

Gas is particularly valuable during periods of high electricity demand and low intermittent renewable output. However, these periods are projected to occur relatively infrequently, due to a combination of low demand growth; increased diversity amongst intermittent renewable capacity coming online, increased interconnection between regions; development of Snowy 2.0 pumped storage facility and numerous utility-scale battery installations.

While access to gas supplies during winter peak periods is critically important for the power system, it is utilised for relatively short periods of time when wholesale electricity prices spike. Gas volumes for power generation in Victoria are projected to be materially lower than observed in recent years.

Changes in gas prices modelled under the with and without Crib Point LNG scenarios are therefore likely to have an immaterial impact on gas volumes dispatched and emission outcomes in the NEM.

4 AEMO 2020 Victorian Gas Planning Report, page 5.

0.0

20.0

40.0

60.0

80.0

100.0

120.0

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

PJ



FIGURE 2.14 MODELLED ELECTRICITY MARKET OUTCOMES FOR VICTORIA: BASE CASE

SOURCE: ACIL ALLEN POWERMARK MODELLING

0

10

20

30

40

50

60

20

00

20

02

20

04

20

06

20

08

20

10

20

12

20

14

20

16

20

18

20

20

20

22

20

24

20

26

20

28

20

30

20

32

20

34

20

36

20

38

20

40

20

42

20

44

20

46

20

48

20

50

TW

h (a

s g

en

era

ted

)

Dispatch by fuel type

Black coal Brown coal Hydro

Natural gas Wind Solar

Energy Requirements

Brown coal56.7%

Hydro7.1%

Natural gas0.4%

Wind30.3%

Solar5.5%

Fuel share of generation in 2030

0

5

10

15

20

GW

Installed capacity by fuel type

Black coal Brown coal HydroNatural gas Wind SolarBattery - Discharge Pump - Discharge Peak DemandAverage Demand

-1,000

-500

0

500

1,000

1,500

2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 2049

MW

Annual change in capacity by fuel type

Black coal Brown coal Hydro Natural gas Wind Solar Battery storage Other

17.6%

23.3%

39.8%

50.6%

0%

10%

20%

30%

40%

50%

60%

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Sh

are

of

ge

ne

ratio

n (

%)

Renewable share of sent-out generation (inc. rooftop PV)

-10,000

-5,000

0

5,000

10,000

15,000

GW

h e

xp

ort

(im

po

rt)

Regional net exports

Exports Imports Net Exports

MARKET IMPACTS OF CRIB POINT TECHNICAL REPORT FINAL A–1

A . G A S M A R K

A GasMark

GasMark Global (GMG) is a generic gas modelling platform developed by ACIL Allen. GMG has the flexibility to represent the unique characteristics of gas markets across the globe, including both pipeline gas and LNG. Its potential applications cover a broad scope — from global LNG trade, through to intra-country and regional market analysis.

GasMark Global Australia (GMG Australia) is an Australian version of the model which focuses specifically on the Australian market (including both eastern Australian and Western Australian modules), but which has the capacity to interface with international LNG markets. The figure below shows the Eastern and Western Australian network representation.

FIGURE A.1 NETWORK REPRESENTATION IN GASMARK

SOURCE: GASMARK


A.1 Settlement

At its core, GMG Australia is a partial spatial equilibrium model. The market is represented by a collection of spatially related nodal objects (supply sources, demand points, LNG liquefaction and receiving facilities), connected via a network of pipeline or LNG shipping elements (in a similar fashion to ‘arks’ within a network model).

The equilibrium solution of the model is found through application of linear programming techniques which seek to maximise the sum of producer and consumer surplus across the entire market simultaneously. The objective function of this solution, which is well established in economic theory5, consists of three terms:

— the integral of the demand price function over demand; minus

— the integral of the supply price function over supply; minus

— the sum of the transportation, conversion and storage costs.

The solution results in an economically efficient system where lower cost sources of supply are utilised before more expensive sources and end-users who have higher willingness to pay are served before those who are less willing to pay. Through the process of maximising producer and consumer surplus, transportation costs are minimised and spatial arbitrage opportunities are eliminated. Each market is cleared with a single competitive price.

Figure A.2seeks to explain diagrammatically a simplified example of the optimisation process. The two charts at the top of Figure A.2 show simple linear demand and supply functions for a particular market. The figures in the middle of Figure A.2 show the integrals of these demand and supply functions, which represent the areas under the demand and supply curves. These are equivalent to the consumer and producer surpluses at each price point along the curve. The figure on the bottom left shows the summation of the consumer and producer surplus, with a maximum clearly evident at a quantity of 900 units. This is equivalent to the equilibrium quantity when demand and supply curves are overlayed as shown in the bottom right figure.

The distinguishing characteristic of spatial price equilibrium models lies in their recognition of the importance of space and transportation costs associated with transporting a commodity from a supply source to a demand centre. Since gas markets are interlinked by a complex series of transportation paths (pipelines, shipping paths) with distinct pricing structures (fixed, zonal or distance based), GMG Australia also includes a detailed network model with these features.

Spatial price equilibrium models have been used to study problems in a number of fields including agriculture, energy markets, mineral economics, as well as in finance. These perfectly competitive partial equilibrium models assume that there are many producers and consumers involved in the production and consumption, respectively, of one or more commodities and that as a result the market settles in an economically efficient fashion. Similar approaches are used within gas market models across the world.

5 The theoretical framework for the market solution used in GMG is attributed to Nobel Prize winning economist Paul Samuelson.


FIGURE A.2 SIMPLIFIED EXAMPLE OF MARKET EQUILIBRIUM AND SETTLEMENT PROCESS

SOURCE: ACIL ALLEN CONSULTING

A.2 Data inputs

The user can establish the level of detail by defining a set of supply regions, customers, demand regions, pipelines and LNG facilities. These sets of basic entities in the model can be very detailed or aggregated as best suits the objectives of the user. A ‘pipeline’ could represent an actual pipeline or a pipeline corridor between a supply and a demand region. A supplier could be a whole gas production basin aggregating the output of many individual fields, or could be a specific producer in a smaller region. Similarly, a demand point could be a single industrial user or an aggregation of small consumers such as the residential and commercial users typically serviced by energy utility companies.

The inputs to GMG Australia can be categorised as follows:

— Existing and potential new sources of gas supply: these are characterised by assumptions about available reserves, production rates, production decline characteristics, and minimum price expectations of the producer. These price expectations may be based on long-run marginal costs of production or on market expectations, including producer’s understandings of substitute prices. The “gas field” objects in the model can also be used to represent LNG import terminals since these are, in


effect, simply alternative sources of gas supply that are not subject to intrinsic reserves limits or production decline functions, but that have similar characteristics in terms of minimum selling prices (representing cost of purchasing LNG plus terminal costs) and maximum delivery (production) rates.

— Existing and potential new gas demand: demand may relate to a specific load such as a power station, or fertiliser plant. Alternatively, it may relate to a group or aggregation of customers, such as the residential or commercial utility load in a particular region or location. Loads are defined in terms of their location, annual and daily gas demand including daily demand profiles, and price tolerance.

— Existing, new and expanded transmission pipeline capacity: pipelines are represented in terms of their geographic location, physical capacity (which may vary over time), flow characteristics (uni-directional or bi-directional) and tariffs.

— Existing and potential new LNG facilities: LNG facilities include liquefaction plants, regasification (receiving) terminals and assumptions regarding shipping costs and routes. LNG facilities play a similar role to pipelines in that they link supply sources with demand. LNG plants and terminals are defined at the plant level and require assumptions with regard to annual throughput capacity and tariffs for conversion.

Existing and potential gas storage facilities: storage facilities (whether UGS or LNG) are defined in terms of total storage capacity, maximum injection and withdrawal rates, cushion gas requirements, storage losses, and price limits for purchase of gas into storage and sale of gas from storage. Storage charges are taken into account via tariffs on the pipelines connecting storage facilities into the transmission pipelines system


ABN 68 102 652 148

ACILALLEN.COM.AU

ABOUT ACIL ALLEN CONSULTING

ACIL ALLEN CONSULTING IS THE

LARGEST INDEPENDENT,

AUSTRALIAN OWNED ECONOMIC

AND PUBLIC POLICY CONSULTANCY.

WE SPECIALISE IN THE USE OF

APPLIED ECONOMICS AND

ECONOMETRICS WITH EMPHASIS ON

THE ANALYSIS, DEVELOPMENT AND

EVALUATION OF POLICY, STRATEGY

AND PROGRAMS.

OUR REPUTATION FOR QUALITY

RESEARCH, CREDIBLE ANALYSIS

AND INNOVATIVE ADVICE HAS BEEN

DEVELOPED OVER A PERIOD OF

MORE THAN THIRTY YEARS.


ABN 68 102 652 148

LEVEL NINE

60 COLLINS STREET

MELBOURNE VIC 3000

AUSTRALIA

T+61 3 8650 6000

LEVEL NINE

50 PITT STREET

SYDNEY NSW 2000

AUSTRALIA

T+61 2 8272 5100

LEVEL FIFTEEN

127 CREEK STREET

BRISBANE QLD 4000

AUSTRALIA

T+61 7 3009 8700

LEVEL SIX


CANBERRA ACT 2601

AUSTRALIA

T+61 2 6103 8200

LEVEL TWELVE

28 THE ESPLANADE

PERTH WA 6000

AUSTRALIA

T+61 8 9449 9600

167 FLINDERS STREET

ADELAIDE SA 5000

AUSTRALIA

T +61 8 8122 4965

ACILALLEN.COM.AU



















1 Introduction

Ashurst act on behalf of AGL Wholesale Gas Limited (AGL) and Hall & Wilcox act on behalf of APA Transmissions Pty Ltd (APA) who jointly propose to develop a Liquefied Natural Gas (LNG) import facility and associated gas transmission pipeline in Westernport, Victoria (the Project).

Ashurst and Hall & Wilcox have jointly engaged me to prepare an independent technical report for the purposes of the public hearing on this matter.

1.1 Report Author

Owen Kelp

Director

ACIL Allen Consulting Pty Ltd

Level 15, 127 Creek Street,

Brisbane QLD 4000

1.2 Qualifications

Graduate Diploma of Applied Finance and Investment from the Financial Services Institute of Australasia (FINSIA – 2005).

Bachelor of Business (Economics and Finance) from Queensland University of Technology – 1999

Owen Kelp is a Director of ACIL Allen Consulting with twenty years of experience specialising in electricity, gas and renewable energy markets. Owen has worked extensively on energy industry matters and across a broad range of assignments including market demand, supply and price forecasting studies; strategic reviews; transmission and distribution networks (project evaluation, throughput forecasts, asset sales and due diligence work); project evaluation (financial modelling, market studies and economic benefits) and regulatory matters.

In electricity, Owen has extensive experience undertaking various modelling projects in Australian wholesale electricity markets (NEM and WEM), including short and long-term outlooks and detailed due diligence for asset sales/acquisitions and transmission studies. Owen has undertaken a number of assignments in relation to renewable energy and environmental certificate markets including outlooks for certificate demand/supply and price outlooks in the context of renewable asset due diligence.

He has authored multi-client studies examining the prospects and impacts of renewable energy development in Australia’s electricity markets. He was also the project manager on an assignment assisting the Commonwealth Government appointed Expert Panel’s review of the Renewable Energy


Target in 2014 and the Energy Security Board in relation to the development of the National Energy Guarantee in 2018.

His energy experience also extends across the gas industry, having undertaken a range of market outlooks, demand/supply studies, commercial analysis, pipeline evaluation and due diligence activities. He has considerable experience in relation to commercial aspects of coal seam gas and conventional gas developments, as well as a good understanding of the interaction between gas and electricity markets. In the area of gas pipeline regulation, Owen has assisted a number of clients and regulators primarily relating to demand forecasts as a key input to transmission and distribution network access arrangements. This work has included methodology assessments of third-party forecasts, as well as undertaking independent forecasting studies. Owen’s detailed knowledge of the workings and outlook for the power generation sector has been key aspect of his work in this area.

1.3 Instructions and information relied upon

I have been instructed to:

a) undertake economic modelling to understand the impact of the Project, and of the Project not proceeding, on the Victorian and the East coast gas markets, including in relation to gas price, supply, and the composition of energy generation

b) prepare a technical report (Report) which sets out the assessment of the modelling referred to in (a) above.

c) identify any further information relevant to the assessment, required to complete the Report.

The information that I have relied upon includes:

— the Environment Effects Statement (EES) for the Project

— the Australian Energy Market Operator (AEMO) 2020 Gas Statement of Opportunities (GSOO) report

— the AEMO 2020 Victorian Gas Planning Report (VGPR)

— ACIL Allen’s internal Gas and Electricity Reference cases (current as at the date of this report).

1.4 This report

This report presents results from economic modelling of the Eastern Australian wholesale gas and electricity markets for the purposes of quantifying the market impacts of the Project.

The modelling draws upon ACIL Allen’s in-house gas Reference case scenario for the Australian wholesale gas market and includes a range of supply and demand assumptions drawn from various publicly available sources (such as AEMO’s 2020 Gas Statement of Opportunities report and Victorian Gas Annual Planning report) and in-house intelligence including detailed market modelling of the National Electricity Market.

As a modelling exercise, the analysis is necessarily a simplification of the real world and utilises fundamental economic concepts to make projections of the gas market’s evolution in Eastern Australia. The results are not intended to represent accurate predictions about market outcomes or utilisation of the Project as the modelling does not consider commercial factors such as ownership structures or contractual positions of individual parties.

The modelling necessarily includes a portion of as-yet undeveloped reserves and resources which are somewhat speculative. This contrasts with other planning exercises, such as the Gas Statement of Opportunities report, which typically only includes currently developed or known supply sources for the purposes of highlighting the scale and timing for new supply and transmission investment to ensure demand is met.

The Base case scenario includes the proposed AGL Crib Point LNG import terminal with up to 160 PJ/a of annual capability and daily capacity of up to 795 TJ/d. This has been run against a scenario in which the Crib Point terminal does not proceed, holding all other assumptions constant.

The gas market modelling included a number of scenarios which test a range of factors including:

— The price at which the AGL terminal can import gas from international markets


— Whether the Narrabri gas supply project proposed by Santos goes ahead in New South Wales (a key market uncertainty in the near-term)

— An alternative scenario in which the Project is not developed, but an alternative import terminal is developed at Port Kembla in NSW.

Modelling outputs include projections for:

— Wholesale gas price outcomes for Victoria

— Utilisation of the Project

— Impacts on Victorian gas consumption

— Impacts on Victorian gas production.


2 P R O J E C T E D M A R K E T I M P A C T S

2 Projected Market impacts

2.1 Gas scenarios examined

The analysis undertaken draws from ACIL Allen’s current Reference case scenario for the Eastern Australian gas market. An overview of key assumptions used in is provided in Table 2.1. Modelling was conducted using GasMark (see Appendix A for details on the model) over the period 2020 to 2040 at a monthly resolution.

TABLE 2.1 REFERENCE CASE ASSUMPTIONS


Global – long term oil price Oil at US $65/bbl

Global – long term exchange rate A$:US$ = 0.75

LNG export price A$11.00/GJ

Gas demand – residential / commercial /

industrial

Future annual demand reflects current trends as demonstrated in the latest Gas Statement of

Opportunities Report from AEMO.

Gas demand – electricity generation GPG daily demand profiles reflect outcomes from ACIL Allen’s current Reference Case electricity

market model for the National Electricity Market. Individual custom profiles for each gas station

reflect modelled daily dispatch of that station.

Gas supply – Bass Strait region Includes new (and recently commissioned) conventional supply in the Bass Strait region including

Halladale–Blackwatch–Speculant (Otway); Kipper–Tuna–Turrum (Gippsland) and Sole

(Gippsland). Also assumes tie-in of additional gas reserves in the Bass Basin (Trefoil,

Gentoo/Rockhopper) which extends life span of the BassGas Project. Long lead time projects

such as South East Remora, Manta, La Bella in the offshore Gippsland and Otway Basins are

assumed to offer new gas supply, with capacity ramping up later in the 2020s and into the 2030s.

Gas supply – Cooper Basin Conventional gas production and deliverability capability from the Cooper Basin reflects currently

developed and committed 2P reserves and contingent resources only. Unconventional production

increases to levels around 30 PJ by year 2030.

Gas supply – Surat/Bowen basins Field developments provide sufficient supply capability to meet Gladstone LNG plant

requirements, with modest excess capacity available to support domestic deliveries. Arrow

Energy’s gas fields are modelled according to recent announcements made with LNG producers

(particularly QCLNG) and their recent FID announcement.

Gas supply - NSW Narrabri development by Santos goes ahead despite the project not receiving the required

regulatory approvals yet and no ultimate decision has been made to proceed. ACIL Allen has

introduced Narrabri into our Base Case and sets supply equivalent to its full capacity as stated by

Santos (75 PJ/a), ramping up to this level over the period 2024 to 2028.



Gas transmission pipelines Capacity of pipelines reflect current installed capacities, with expansions (if deemed commercial)

required to ensure that gas movements are not constrained by pipeline capacity over the long-

term. In this scenario, the only material new pipeline infrastructure includes that required to bring

the Narrabri Project to market.

Queensland LNG exports Liquefaction capacity at Gladstone is limited to the currently committed six trains (nominal 25.3

Mt/a LNG) with each plant operating at a level corresponding to its current LNG contract levels.

As a result, the effective output of the six trains is 22 Mt/a LNG. However, maximum capacity is

set at nameplate capacity.

LNG import terminals One LNG terminal (Crib Point) at up to 160 PJ/a capacity, delivery capability up to 795 TJ/d.

COVID-19 impact COVID-19 impacts the market over the short term (12-24 months) but the energy market begins

to recover strongly from 2021. The impacts are incorporated via adjustments to the level of LNG

exports and reduced domestic demand.

SOURCE: ACIL ALLEN GAS REFERENCE CASE JULY 2020

The only change to ACIL Allen’s standard Reference case assumptions has been to align the Crib Point import terminal capacity with that outlined with the Project EES document.

Table 2.2 details the various scenarios examined.

One of the key sensitivities is the cost at which LNG can be imported into Victoria relative to prevailing domestic prices. This will be dependent upon Asia-Pacific LNG spot prices throughout the year relative to LNG contract prices. It is likely that LNG spot cargoes would be acquired for less than annual average LNG contract prices as:

a) LNG spot prices (which are determined by market supply-demand dynamics) are generally less than long-term contract prices which have a strong oil linkage

b) cargoes could be acquired during the northern hemisphere summer when aggregate gas demand and prices are seasonally lower.

While the Base case assumes an import cost of A$9.50/GJ, the modelling has also examined a High and Low import cost sensitivity around this value.

The modelling also looks at the impact of the Narrabri gas project in NSW not proceeding as this is assumed to occur in ACIL Allen’s Reference case scenario and finally a scenario in which an alternative import terminal is developed at Port Kembla in NSW rather than Crib Point.

TABLE 2.2 GAS MARKET SCENARIOS EXAMINED

Scenario Description

Base case ACIL Allen Reference case assumptions. Crib Point import terminal

developed; assumed import cost of A$9.50/GJ

No terminal case No import terminals developed

Base case (High import cost) Crib Point import terminal developed; assumed import cost of

A$10.50/GJ

Base case (Low import cost) Crib Point import terminal developed; assumed import cost of

A$8.00/GJ

No terminal case; No Narrabri case No import terminals developed; Narrabri gas project does not proceed

No Narrabri case Crib Point import terminal developed; assumed import cost of


No Narrabri case (Low import cost) Crib Point import terminal developed; assumed import cost of


Port Kembla terminal case Crib Point import terminal not developed; Port Kembla import terminal

proceeds (import cost of A$9.50/GJ)


2.2 Price impacts

Gas market modelling suggests the impact of the Project will be to put downward pressure on Victorian prices (represented by the price of wholesale gas at the Melbourne city-gate) over the projection period.

The figure below shows the projected annual average price for wholesale gas in Melbourne under the Base case scenarios at various assumed import prices relative to a No terminal case. Supply to Victoria is under pressure by the late 2020’s due to the depletion of reserves in existing Basins. Together, with minimal investment predicted in offshore Victorian basins, gas prices rise quickly above $10/GJ (real 2020 dollars) in the 2030s and above $12/GJ by the end of the projection period.

The impact of the Project will depend to some extent on the relative cost of imports versus prevailing wholesale prices in the domestic market. The lower the import cost, the greater the utilisation of LNG imports and the more downward pressure is exerted on domestic prices. The impact on 2030 outcomes as modelled, ranges from $0.20/GJ (2%) lower under the High import cost assumption through to $1.29/GJ (13%) lower under the Low import cost assumption. By 2040, this range increases to $1.63/GJ (13%) lower and $3.40/GJ (27%), respectively.

FIGURE 2.1 PROJECTED WHOLESALE GAS PRICES FOR MELBOURNE CITY GATE (REAL 2020 $/GJ)


The market impacts of the Project will also depend upon other gas demand and supply developments which occur over the projection period. Figure 2.2 shows the impact of the Project upon price outcomes is larger when the supply-demand balance is tighter. In these scenarios, the proposed Narrabri gas project in NSW is assumed not to proceed.1

1 Narrabri is assumed to come online around 2024 and produces 75 PJ per annum at full capacity in the preceding scenarios.

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11.00

12.00

13.00

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Rea

l 202

0 $/

GJ



FIGURE 2.2 PROJECTED WHOLESALE GAS PRICES FOR MELBOURNE CITY GATE WITH NARRABRI NOT DEVELOPED, (REAL 2020 $/GJ)


2.3 LNG import terminal utilisation

Figure 2.3 shows modelled utilisation of the project under the Base case scenarios. The Base case sees annual volumes of around 40 PJ/a, increasing over time as the domestic supply-demand balance tightens and Victoria’s reliance on imported gas increases. The High and Low import price sensitivities highlight that the utilisation of the facility will be dependent on the relative LNG import prices.

FIGURE 2.3 PROJECTED CRIB POINT UTILISATION (PJ)


Initially, the Project is modelled to operate more like a ‘peaker’, adding supply to the market during peak demand periods (mainly during the winter months) when prevailing spot gas prices are high (as shown in Figure 2.4). However, its role transforms from mainly a peaker to a baseload gas supplier over the projection period due to depleting resources and higher cost supply, the terminal is called on to import year-round, not just in the winter months.

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11.00

12.00

13.00

14.00

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Rea

l 202

0 $/

GJ


0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

PJ



FIGURE 2.4 PROJECTED CRIB POINT MONTHLY UTILISATION FOR SELECTED YEARS: BASE CASE (PJ)


As shown below, the utilisation of the facility is projected to be higher should the Narrabri gas project not proceed. In these scenarios, the Project is projected to be called on more in both the initial years and later in the projection period. The terminal is projected to become a significant source of year-round supply if Narrabri is not developed, capping out at the assumed import capacity of 160 PJ/a by the late-2030’s under the Low import cost case.

FIGURE 2.5 PROJECTED CRIB POINT UTILISATION: NO NARRABRI SENSITIVITY (PJ)


We understand that there may be a practical physical limitation on the ability of the import terminal to only operate for winter periods. Should this be the case, AGL may be required to operate the facility all year round and inject at least some gas into the Victorian grid for non-winter months.2 If this is the case, injection volumes may be higher than those shown, and the facility would be expected to have a further dampening effect on Victorian wholesale gas price outcomes.

2.4 Impacts on gas supply into Victoria

The main sources of gas supply for the south-eastern Australian market are the Gippsland, Otway and Bass Basins located principally offshore in Bass Strait. These supply sources have become

2 ACIL Allen have been informed that this could be up to 2 PJ/month.

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

PJ

2024 2030 2035 2040

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

180.0

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

PJ



increasingly important to the Eastern Australian domestic market as much of the production in Central Australia (Cooper Basin) is being directed to LNG export markets through Gladstone, rather than to domestic markets.

The Gippsland Basin contains the largest conventional gas reserves in Eastern Australia, with the majority of this controlled by the Esso/BHP Gippsland Basin Joint Venture (GBJV).3 However these legacy fields are now in decline and production is expected to steadily fall over the coming decade. Falling rates of supply are expected to be most evident in the winter months as peak day deliverability declines. Even with five processing plants in Victoria (Longford, Sole, Lang Lang (BassGas), Otway and Casino), supply is highly reliant on the Longford processing plant which accounts for more than 80 per cent of supply. Figure 2.6 shows the modelled Victorian gas production by Basin in the scenario with no import terminals.

FIGURE 2.6 PROJECTED VICTORIAN GAS SUPPLY WITH NO IMPORT TERMINAL (PJ)


This is contrasted with Figure 2.7 which shows the development of the Crib Point terminal resulting in a material level of incremental supply from Victoria. This enables Victoria to be self-sufficient for longer on an annual basis but still reliant imported gas from other States through peak winter months.

FIGURE 2.7 PROJECTED VICTORIAN GAS SUPPLY WITH CRIB POINT IMPORT TERMINAL (PJ)


Figure 2.8 shows the impact of the incremental supply from the LNG import terminal on Victorian net exports to neighbouring States. Without the terminal, net exports from Victoria decline significantly,

3 In the past, Esso/BHP jointly marketed their Gippsland Basin gas entitlements; that arrangement is now coming to an end, with the joint venture parties separately marketing their gas entitlements since January 2019.

0

50

100

150

200

250

300

350

400

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

GBJV Other Gippsland Bass Casino, Minerva, Henry Other Otway

0

50

100

150

200

250

300

350

400

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

GBJV Other Gippsland Bass Casino, Minerva, Henry Other Otway Crib Point LNG


reaching a net zero export position in the early 2030’s and becomes increasingly reliant on imports from other States (particularly NSW) through to 2040.

In contrast, the Base case which includes the Crib Point import terminal results in Victoria remaining self-sufficient throughout the projection period. The importance of the import terminal for the Eastern Australian market is even more pronounced in scenarios in which the Narrabri CSG project does not proceed.

FIGURE 2.8 PROJECTED VICTORIAN MONTHLY NET EXPORTS TO OTHER STATES: WITH AND WITHOUT CRIB POINT TERMINAL

Note: Aggregate net flow calculated as sum of monthly projected flows on SEAGas, VIC-NSW interconnect, Eastern Gas Pipeline and Tasmanian Gas Pipeline


2.5 Impacts on gas consumption

Figure 2.9 present a comparison of modelled Eastern Australian gas consumption in the Base case and No import terminal cases, along with a comparison against the AEMO 2020 GSOO demand forecast. ACIL Allen’s Base case is lower than AEMO through to 2024, with much of this driven by a reduction in gas-fired generation resulting from near-term renewable capacity coming online. The two series converge from 2026 with ACIL Allen’s electricity market modelling projecting an early staged closure of Yallourn power station at this point, with longer-term declines in consumption relating to fuel switching stemming from high gas prices.

Projected aggregate gas consumption is lower in the No Terminal case (as shown in Figure 2.10), as a result of the higher wholesale gas prices that result under this scenario. Most of these price elasticity effects occur in Victoria, although higher prices also flow through other States. Gas consumption is projected to be around 24 PJ (5%) lower in 2030, rising to 45 PJ (10%) by 2040. The figure also shows the data broken down by end user category. The demand reduction is projected to occur in

-15

-10

-5

0

5

10

15

20Ja

n-20

Oct

-20

Jul-2

1

Apr

-22

Jan-

23

Oct

-23

Jul-2

4

Apr

-25

Jan-

26

Oct

-26

Jul-2

7

Apr

-28

Jan-

29

Oct

-29

Jul-3

0

Apr

-31

Jan-

32

Oct

-32

Jul-3

3

Apr

-34

Jan-

35

Oct

-35

Jul-3

6

Apr

-37

Jan-

38

Oct

-38

Jul-3

9

Apr

-40

PJ/

mon

th

No import terminal


-15

-10

-5

0

5

10

15

20

Jan-

20

Oct

-20

Jul-2

1

Apr

-22

Jan-

23

Oct

-23

Jul-2

4

Apr

-25

Jan-

26

Oct

-26

Jul-2

7

Apr

-28

Jan-

29

Oct

-29

Jul-3

0

Apr

-31

Jan-

32

Oct

-32

Jul-3

3

Apr

-34

Jan-

35

Oct

-35

Jul-3

6

Apr

-37

Jan-

38

Oct

-38

Jul-3

9

Apr

-40

PJ/

mon

th

Base case



industrial and commercial/residential users, with the reduction in gas-fired power generation accounting for a smaller proportion.

FIGURE 2.9 PROJECTED EASTERN AUSTRALIAN GAS CONSUMPTION WITH AND WITHOUT IMPORT TERMINAL (PJ)

Note: Eastern Australia = QLD, NSW/ACT, VIC, SA and TAS

SOURCE: GASMARK MODELLING, AEMO 2020 GAS STATEMENT OF OPPORTUNITIES

FIGURE 2.10 PROJECTED IMPACT ON EASTERN AUSTRALIAN GAS CONSUMPTION WITHOUT IMPORT TERMINAL (PJ): BY STATE AND BY END USER CATEGORY


0

100

200

300

400

500

600

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

Base case No import terminals AEMO 2020 GSOO

-50

-45

-40

-35

-30

-25

-20

-15

-10

-5

0

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

Queensland New South Wales Victoria South Australia Tasmania Australian Capital Territory

-50

-45

-40

-35

-30

-25

-20

-15

-10

-5

0

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

PJ

Power generation Industrial Commercial/Residential


Figure 2.11 presents the projected impact on aggregate gas consumption volumes in Victoria resulting from the development of the Project. Consumption volumes are around 12.2 PJ (6%) lower by 2030, with this rising to 29.3 PJ (16%) lower by 2040 in the absence of the terminal.

FIGURE 2.11 PROJECTED IMPACT ON VICTORIAN GAS CONSUMPTION WITHOUT IMPORT TERMINAL (PJ)


2.6 Port Kembla development

The final gas market scenario examined, models the impact of an alternative LNG import terminal proceeding – specifically the Port Kembla terminal proposed by Australian Industrial Energy (AIE). This scenario assumes the import terminal to be the same size as used in the Base case for Crib Point, with the only difference being the geographical location. Figure 2.12 shows the resulting price outcomes for Melbourne in comparison with the Base case scenario. Price outcomes are broadly the same through to the late 2020’s before the Port Kembla scenario rising slightly more than the Base case. This is due to Victoria initially exporting less gas in the early years to NSW under the Port Kembla case, with little impact on Victorian outcomes, but relying on imports and incremental transmission costs late in the projection period (as shown previously in Figure 2.8).

FIGURE 2.12 PROJECTED WHOLESALE MELBOURNE CITY GATE GAS PRICES WITH PORT KEMBLA LNG (REAL 2020 $/GJ)


-40.0

-35.0

-30.0

-25.0

-20.0

-15.0

-10.0

-5.0

0.0

5.0

0

50

100

150

200

250

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Cha

nge

(PJ)

PJ

Change (PJ) Base case No import terminal

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11.00

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Rea

l 202

0 $/

GJ



Figure 2.13 compares import volumes between the two scenarios, showing that a Crib Point or Port Kembla location yield similar LNG import outcomes within the modelling.

FIGURE 2.13 COMPARISON OF PROJECTED IMPORT VOLUMES


2.7 Electricity market projections

Figure 2.14 shows projected outcomes for Victoria from ACIL Allen’s RC53 Reference case electricity market outlook, which utilises the gas prices from the Gas Base Case (i.e. with Crib Point proceeding).

Due to relatively high gas prices and low levels of price volatility projected in the near-term, gas-fired generation is projected to play a small supporting role within the generation mix. This is similar to modelling conducted by AEMO within the Victorian Gas Planning Report for 2020 which has gas-fired generation volumes falling by 75% in the near-term, with gas use declining from 20 PJ in 2019 (actual) down to 5 PJ expected for 2021.4

Gas is particularly valuable during periods of high electricity demand and low intermittent renewable output. However, these periods are projected to occur relatively infrequently, due to a combination of low demand growth; increased diversity amongst intermittent renewable capacity coming online, increased interconnection between regions; development of Snowy 2.0 pumped storage facility and numerous utility-scale battery installations.

While access to gas supplies during winter peak periods is critically important for the power system, it is utilised for relatively short periods of time when wholesale electricity prices spike. Gas volumes for power generation in Victoria are projected to be materially lower than observed in recent years.

Changes in gas prices modelled under the with and without Crib Point LNG scenarios are therefore likely to have an immaterial impact on gas volumes dispatched and emission outcomes in the NEM.

4 AEMO 2020 Victorian Gas Planning Report, page 5.

0.0

20.0

40.0

60.0

80.0

100.0

120.0

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

PJ



FIGURE 2.14 MODELLED ELECTRICITY MARKET OUTCOMES FOR VICTORIA: BASE CASE

SOURCE: ACIL ALLEN POWERMARK MODELLING

0

10

20

30

40

50

60

20

00

20

02

20

04

20

06

20

08

20

10

20

12

20

14

20

16

20

18

20

20

20

22

20

24

20

26

20

28

20

30

20

32

20

34

20

36

20

38

20

40

20

42

20

44

20

46

20

48

20

50

TW

h (a

s g

en

era

ted

)

Dispatch by fuel type

Black coal Brown coal Hydro

Natural gas Wind Solar

Energy Requirements

Brown coal56.7%

Hydro7.1%

Natural gas0.4%

Wind30.3%

Solar5.5%

Fuel share of generation in 2030

0

5

10

15

20

GW

Installed capacity by fuel type

Black coal Brown coal HydroNatural gas Wind SolarBattery - Discharge Pump - Discharge Peak DemandAverage Demand

-1,000

-500

0

500

1,000

1,500

2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 2049

MW

Annual change in capacity by fuel type

Black coal Brown coal Hydro Natural gas Wind Solar Battery storage Other

17.6%

23.3%

39.8%

50.6%

0%

10%

20%

30%

40%

50%

60%

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Sh

are

of

ge

ne

ratio

n (

%)

Renewable share of sent-out generation (inc. rooftop PV)

-10,000

-5,000

0

5,000

10,000

15,000

GW

h e

xp

ort

(im

po

rt)

Regional net exports

Exports Imports Net Exports


A . G A S M A R K

A GasMark

GasMark Global (GMG) is a generic gas modelling platform developed by ACIL Allen. GMG has the flexibility to represent the unique characteristics of gas markets across the globe, including both pipeline gas and LNG. Its potential applications cover a broad scope — from global LNG trade, through to intra-country and regional market analysis.

GasMark Global Australia (GMG Australia) is an Australian version of the model which focuses specifically on the Australian market (including both eastern Australian and Western Australian modules), but which has the capacity to interface with international LNG markets. The figure below shows the Eastern and Western Australian network representation.

FIGURE A.1 NETWORK REPRESENTATION IN GASMARK

SOURCE: GASMARK


A.1 Settlement

At its core, GMG Australia is a partial spatial equilibrium model. The market is represented by a collection of spatially related nodal objects (supply sources, demand points, LNG liquefaction and receiving facilities), connected via a network of pipeline or LNG shipping elements (in a similar fashion to ‘arks’ within a network model).

The equilibrium solution of the model is found through application of linear programming techniques which seek to maximise the sum of producer and consumer surplus across the entire market simultaneously. The objective function of this solution, which is well established in economic theory5, consists of three terms:

— the integral of the demand price function over demand; minus

— the integral of the supply price function over supply; minus

— the sum of the transportation, conversion and storage costs.

The solution results in an economically efficient system where lower cost sources of supply are utilised before more expensive sources and end-users who have higher willingness to pay are served before those who are less willing to pay. Through the process of maximising producer and consumer surplus, transportation costs are minimised and spatial arbitrage opportunities are eliminated. Each market is cleared with a single competitive price.

Figure A.2seeks to explain diagrammatically a simplified example of the optimisation process. The two charts at the top of Figure A.2 show simple linear demand and supply functions for a particular market. The figures in the middle of Figure A.2 show the integrals of these demand and supply functions, which represent the areas under the demand and supply curves. These are equivalent to the consumer and producer surpluses at each price point along the curve. The figure on the bottom left shows the summation of the consumer and producer surplus, with a maximum clearly evident at a quantity of 900 units. This is equivalent to the equilibrium quantity when demand and supply curves are overlayed as shown in the bottom right figure.

The distinguishing characteristic of spatial price equilibrium models lies in their recognition of the importance of space and transportation costs associated with transporting a commodity from a supply source to a demand centre. Since gas markets are interlinked by a complex series of transportation paths (pipelines, shipping paths) with distinct pricing structures (fixed, zonal or distance based), GMG Australia also includes a detailed network model with these features.

Spatial price equilibrium models have been used to study problems in a number of fields including agriculture, energy markets, mineral economics, as well as in finance. These perfectly competitive partial equilibrium models assume that there are many producers and consumers involved in the production and consumption, respectively, of one or more commodities and that as a result the market settles in an economically efficient fashion. Similar approaches are used within gas market models across the world.

5 The theoretical framework for the market solution used in GMG is attributed to Nobel Prize winning economist Paul Samuelson.


FIGURE A.2 SIMPLIFIED EXAMPLE OF MARKET EQUILIBRIUM AND SETTLEMENT PROCESS

SOURCE: ACIL ALLEN CONSULTING

A.2 Data inputs

The user can establish the level of detail by defining a set of supply regions, customers, demand regions, pipelines and LNG facilities. These sets of basic entities in the model can be very detailed or aggregated as best suits the objectives of the user. A ‘pipeline’ could represent an actual pipeline or a pipeline corridor between a supply and a demand region. A supplier could be a whole gas production basin aggregating the output of many individual fields, or could be a specific producer in a smaller region. Similarly, a demand point could be a single industrial user or an aggregation of small consumers such as the residential and commercial users typically serviced by energy utility companies.

The inputs to GMG Australia can be categorised as follows:

— Existing and potential new sources of gas supply: these are characterised by assumptions about available reserves, production rates, production decline characteristics, and minimum price expectations of the producer. These price expectations may be based on long-run marginal costs of production or on market expectations, including producer’s understandings of substitute prices. The “gas field” objects in the model can also be used to represent LNG import terminals since these are, in


effect, simply alternative sources of gas supply that are not subject to intrinsic reserves limits or production decline functions, but that have similar characteristics in terms of minimum selling prices (representing cost of purchasing LNG plus terminal costs) and maximum delivery (production) rates.

— Existing and potential new gas demand: demand may relate to a specific load such as a power station, or fertiliser plant. Alternatively, it may relate to a group or aggregation of customers, such as the residential or commercial utility load in a particular region or location. Loads are defined in terms of their location, annual and daily gas demand including daily demand profiles, and price tolerance.

— Existing, new and expanded transmission pipeline capacity: pipelines are represented in terms of their geographic location, physical capacity (which may vary over time), flow characteristics (uni-directional or bi-directional) and tariffs.

— Existing and potential new LNG facilities: LNG facilities include liquefaction plants, regasification (receiving) terminals and assumptions regarding shipping costs and routes. LNG facilities play a similar role to pipelines in that they link supply sources with demand. LNG plants and terminals are defined at the plant level and require assumptions with regard to annual throughput capacity and tariffs for conversion.

Existing and potential gas storage facilities: storage facilities (whether UGS or LNG) are defined in terms of total storage capacity, maximum injection and withdrawal rates, cushion gas requirements, storage losses, and price limits for purchase of gas into storage and sale of gas from storage. Storage charges are taken into account via tariffs on the pipelines connecting storage facilities into the transmission pipelines system


ABN 68 102 652 148

ACILALLEN.COM.AU

ABOUT ACIL ALLEN CONSULTING

ACIL ALLEN CONSULTING IS THE

LARGEST INDEPENDENT,

AUSTRALIAN OWNED ECONOMIC

AND PUBLIC POLICY CONSULTANCY.

WE SPECIALISE IN THE USE OF

APPLIED ECONOMICS AND

ECONOMETRICS WITH EMPHASIS ON

THE ANALYSIS, DEVELOPMENT AND

EVALUATION OF POLICY, STRATEGY

AND PROGRAMS.

OUR REPUTATION FOR QUALITY

RESEARCH, CREDIBLE ANALYSIS

AND INNOVATIVE ADVICE HAS BEEN

DEVELOPED OVER A PERIOD OF

MORE THAN THIRTY YEARS.