MC Livesey QC Bar Chambers 30 August 2018

Report to the Honourable Vickie Chapman MP,

Attorney-General for the State of South Australia

into the Procurement of Diesel Generators

M.C. Livesey QC

Bar Chambers

30 August 2018

Liability limited by a scheme approved under professional standards legislation

Contents Introduction ...... 3 Summary of Answers to the Terms of Reference ...... 4 First Term of Reference ...... 4 Second Term of Reference...... 7 Third Term of Reference ...... 7 Fourth Term of Reference ...... 8 Context for the generator procurement process ...... 9 The requirements of procurement ...... 12 Short-term electricity generation procurement ...... 15 The Aurecon draft concept and cost estimate ...... 25 State owned gas-fired electricity generation plant ...... 26 The Public Works Committee ...... 27 Developments in November 2017 ...... 31 Procurement and relocation: The State-owned emergency power plant ...... 34 The First Term of Reference ...... 36 The Second Term of Reference ...... 39 The Third Term of Reference ...... 42 The Fourth Term of Reference ...... 42 Conclusion ...... 43 Attachment 1 – Initial Request for Documents ...... 45 Attachment 2 – Responses to Request for Documents, Further Requests ...... 46

Introduction

1. On 3 April 2018 I was appointed to the role of Special Investigator to examine the procurement of nine diesel generators by the former Government.1

2. I was instructed to review all relevant South Australian Government files and other documents and to report by 30 June 2018 on the following Terms of Reference:

2.1. The lease and subsequent purchase of 9 aero-derivative turbines from APR Energy and, in particular, whether the purchase option is binding, and what advantage, if any, there was in exercising the option early;

2.2. Whether all procurement policies and guidelines were followed in exercising the lease and purchase option;

2.3. The financial exposure of the State and any other relevant matters arising from these matters;

2.4. Options open to the government with regard to the future management and ownership of the turbines and the financial implications of such options.

3. I have been assisted by officers in your Department, by officers in the Department of Treasury and Finance (Treasury), and by officers and contractors in the Department of the Premier and Cabinet (DPC), primarily those who formed part of the “Energy Team”, tasked with implementing relevant aspects of the former government’s “Energy Plan”. This assistance included responses to my requests for all relevant documents.2

4. This report was due on 30 June 2018. However, as I was unable to access the key submissions made to Cabinet,3 which I was told contained financial and other analyses concerning the decision to obtain, and ultimately to exercise, the option to purchase on 28 November 2017, an opportunity was given to the Opposition Leader to consent to their release. Ultimately consent to see those submissions was not given. Apart from one spreadsheet supplied to me in connection with my investigation,4 I have seen no comprehensive or contemporaneous independent financial analysis of the long-term implications of exercising the option when it was announced in August 2017, or when it was exercised in November 2017. Naturally, that analysis may be contained in documents that I have not seen.

1 Confirmed by letter dated 4 April 2018 from the Acting Chief Executive, Attorney-General’s Department (AGD). 2 Attachment 1 is my request for documents on 6 April 2018. Attachment 2 is an explanation of the responses received, some of the meetings and conversations held in connection with my investigation, and a listing of all documents provided to me by officers of the “Energy Team”. 3 I wrote to DPC on 23 May but was not advised until after 5pm on Friday, 28 June 2018 that my request had been referred to the Leader of the Opposition – see Attachment 2. 4 “NPV Reports: Evaluation Table, APR Turbine Buyout Options – Draft: 200MW Temporary Generation – Financial Buyout Model”, prepared by SA Power Networks on 12 June 2017.

5. It is important to recognise that this investigation is not a Royal Commission, and I have no power to compel information or evidence.5 I was not authorised to conduct hearings. In addition, I am not asked to comment upon, or determine the responsibility for, decision-making by any particular person. Accordingly, my report is expressed in general terms and without whatever advantage might be associated with giving those who were closely involved any opportunity to comment on any aspect of this report. In the main, my report is based on my review of the various documents supplied to me. I have treated the documents supplied to me as comprehensive responses to my requests. I have made my findings on the balance of probabilities, assuming the documents supplied to me are genuine and accurate records of what they purport to contain.

6. In what follows I have initially set out, really by way of summary, my answers to the Terms of Reference, followed by a narrative review of the information provided to me as the result of meetings and conversations with various department officers, as well as from my review of the folders of documents provided, together with a volume of email correspondence, before considering each of the terms in more detail. I have not attempted anything like a comprehensive exposition of the many complex engineering and economic questions inevitably raised when considering issues associated with the supply of electricity to South Australian consumers, whether over the last few years or over the potential operating life of the turbines, 25 years into the future. Summary of Answers to the Terms of Reference

7. As to each of the Terms of Reference:

First Term of Reference

7.1. The lease and purchase of nine turbines was undertaken as one part of the former government’s “Energy Plan”, intended to provide “energy security” in the form of electricity supply to South Australian consumers during emergencies caused by disruption to supply from the Australian electricity market. The turbines were intended to avoid further ‘black-outs’ of the kind experienced in South Australia during late 2016, early 2017. Initially the turbines were intended as a short-term option, to be based at two sites, and available if required in emergencies: they were procured under a lease arrangement with an initial period of 13 months and a further 12-month optional lease period.

7.2. The lease arrangements included an option to purchase granted by deed in August 2017, following a report to the Joint Steering Committee in June 2017 and preliminary relocation analysis by Aurecon in July 2017. An announcement of the decision to acquire was made by the then Premier and Energy Minister in early August 2017, rather than proceed with the separate construction of a permanent gas-fired emergency power station. More detailed analysis of relocation options was undertaken by Aurecon in October 2017.

5 Cf., Royal Commissions Act 1917, s 10

By late November 2017 it was decided to exercise the option to purchase the turbines, although consideration had been given to this step from June 2017.

7.2.1. The Option Exercise Notice was executed by the then Treasurer and Energy Minister, and witnessed by the then Premier on 28 November 2017. On the same day the Asset Sale Contract was executed by the Energy Minister and witnessed by a senior officer. The exercise of the option, and the Asset Sale Contract, are binding on the State of South Australia.

7.2.2. It is difficult to determine the concrete advantage associated with exercising the option early. By November 2017 the short-term generation facilities were in place, ready for the summer of 2017/2018. There may have been some assistance to early planning for the relocation of the turbines to one site with access to a gas connection, and concern about the approach of the “caretaker” period from 21 February 2018 ahead of the State election in March 2018.6 However it is not easy to determine how the logistics associated with planning for the relocation of the turbines would have suffered if delayed until after the State election.

7.2.3. The financial consequences associated with exercising the option early are quite unclear. On one view of it, there was no financial advantage associated with the early exercise of the option. Whilst the exercise of the option ‘saved’ lease payments of at least $50 million during the second lease period, these are dwarfed by the $267.5 million in costs associated with relocation and ongoing operation and maintenance for a period estimated to last at least 10 years with provision for up to 25 years. The assumption appears to have been that it was ‘cheaper’ to exercise the option and pay $227 million rather than spend something in the range $402 million to $474 million building a new, permanent gas-fired emergency plant.7

7.2.4. That assumption is correct only if a permanent emergency plant was and is needed.

6 By the Electoral Act 1985, s 47(2a) in the case of a general election for the House of Assembly, the writ or writs for the elections in all House of Assembly districts must be issued 28 days before the date fixed for the polling in each district under s 48. By convention, on the issue of the writs the government assumes a 'caretaker' role and avoids decisions that would limit the freedom of action of an incoming government. The public sector must also adopt practices to safeguard its neutrality. See: https://dpc.sa.gov.au/what-we-do/services-for-government/cabinet-office-and-public-value- online/caretaker-conventions. See also Selway, "The Constitution of South Australia", Federation Press, 1997, [4.2.3]. 7 Minute from Mr Sam Crafter, Executive Director, Energy Plan Implantation to the DPC Accredited Purchasing Unit dated 19 October 2017.

7.2.5. Critically, what remains unclear is what consideration was given to whether this emergency generation facility was actually needed permanently, and certainly beyond the lease periods designed to meet forecast shortfalls during the summers of 2017/2018 and 2018/2019. The turbines were only ever intended as an emergency option, to be called on in rare, though admittedly distressing potential black-out events. The effects of black-outs undoubtedly involve both large expense and potential risks to life and property. Planning to avoid the effects of forecast shortfalls in electricity supply in the short-term was prescient, necessary and effective.

7.2.6. However one could not regard the exercise of the option as involving any ‘saving’ unless the need for a permanent facility was effectively and persuasively demonstrated. Given the rapidly changing nature of the Australian electricity market it could not be assumed that a permanent facility would be needed for up to 25 years into the future. Whether these matters received consideration by the former Government when it decided to exercise the option is unclear. The obvious risk is that the decision to exercise the option committed the State to ownership of a permanent, emergency electricity generation facility that would not be needed after the lease periods (or indeed after any agreed extended lease period) expired in the short-term.

7.2.7. Though I do not have access to the key Cabinet submission in November 2017, the early exercise of the option only 4 months before the State election appears to have been made without the benefit of any contemporaneous independent expert analysis or report into the effect of binding the State to ownership of an emergency facility over a period beyond the 25-month lease (or any agreed further lease extension). One would have expected the requisite analysis to assess the need for a permanent facility and:

• estimate the need for the emergency facility beyond the short-term, and potentially for up to 25 years;

• explain or make provision for likely changes and developments in technology associated with electricity generation and distribution, giving consideration to the development or anticipated availability of other forms of electricity generation locally and nationally (including from renewable sources);

• allow for forecasts or any likely changes in the nature of the Australian electricity distribution market, whether through new operators entering the market or from better coordination of resources, for example through AEMO; and

• consider the marketability of the turbines in the event that it was decided that they were no longer required after the initial 25-month lease periods (or any agreed extension to the lease), or at any stage before, as well as during the period of up to 25 years following permanent relocation.

Second Term of Reference

7.3. In general terms there appears to have been close adherence to State procurement and Public Works requirements across a range of acquisition and procurement decisions.

7.4. However whilst the exercise of the option to purchase the turbines was mentioned internally in Joint Steering Committee meetings before entry into Call Option Deed on 7 August 2017, and by 15 August 2017 it was described in the Public Works Committee’s Final Report as “the Government’s preferred option”, neither the obtaining nor exercise of the option was made the subject of any specific procurement approval from the State Procurement Board, whether before or at the time it was exercised in November 2017. It was later mentioned during an informal discussion with the State Procurement Board in October 2017, and was unquestionably part of the context for the approval sought from the Board in connection with relocation, operation and maintenance in the period December 2017 to February 2018.

7.5. State Procurement Board approval was probably required before the option was obtained, and on any view, before it was exercised and the State was thereby committed to its acquisition. That was not done. Rather, it seems to have been assumed, erroneously in my opinion, that the delegation granted by the State Procurement Board to the Chief Executive, DPC, on 13 April 2017 included the authority to enter into and ultimately to exercise the option to purchase.

Third Term of Reference

7.6. The financial exposure to the State associated with the exercise of the option to purchase and relocation has been estimated in different ways at different times over the last year.

7.7. Some estimates have suggested a present cost in the range $411.5 million to $427 million.8 These estimates included initial lease and associated costs, as well as the cost of acquisition of $227 million (due at the end of the 13 month lease period in November 2018).

8 Minute from Mr Sam Crafter, Executive Director, Energy Plan Implantation to the DPC accredited purchasing unit dated 19 October 2017, page 2. See also the Treasury Minute dated 26 March 2018, page 3, suggesting a total cost exceeding $427 million.

7.8. However this range does not properly bring to account all of the costs associated with operation and maintenance over the potential 25-year period. DPC initially estimated these at $187.5 million,9 and ultimately the State Procurement Board described the total anticipated cost of relocation construction, operation and maintenance (including all extension options), as being $267.5 million.10

7.9. The likely overall cost will be at least $494.5 million, in addition to initial lease and associated costs for the first 13 months of around $115 million, a total of $609.5 million.11

7.10. Whilst this exceeds the former Government’s $550 million allocation for its “Energy Plan”, some of the costs will not be met for years if not decades into the future.

Fourth Term of Reference

7.11. In my view the Government of South Australia is obliged to proceed on the basis that the State is contractually bound to purchase the turbines under the Asset Sale Contract. Whilst it could legislate to extricate itself from that contract, that would raise very serious ‘sovereign risk’ issues and set a concerning precedent for future contractual relations with a range of potential suppliers of goods and services to this State.

7.12. In my opinion the steps available to the current government include:

7.12.1. Commencing negotiations with APR to attempt to agree an extension to the lease period, as well as an agreement that the State be released from proceeding to completion of the Asset Sale Contract;

7.12.2. Proceeding to completion for the purchase of the turbines at a cost of $227 million and proceeding with relocation expenditures estimated at $267.5 million over a potential 25-year period; and

7.12.3. The marketing and sale of the turbines at some stage following completion of the Asset Sale Contract, whether to APR Energy or another interested operator, ideally before relocation, operation and maintenance obligations are incurred.

9 Correspondence from Dr Tahnya Donaghy, acting Chief Executive, to the State Procurement Board dated 5 January 2018. 10 Correspondence from Ms Nicolle Rantanen, Presiding Member, State Procurement Board, to Dr Don Russell, Chief Executive DPC, dated 8 February 2018. The explanation is probably that the estimated cost of relocation is $80 million and the estimated cost of operation and maintenance is $187.5 million. 11 ‘Detailed Purchase Recommendation’ - “Short-Term Electricity Generation” dated 27 June 2017, page 10. That is, $227 million plus $267.5 million ($494.5 million) in addition to initial lease and associated costs of $115 million.

7.13. I have no information on the appetite of APR to renegotiate the lease or Asset Sale Contract arrangements, nor the extent of any financial compensation that may be required by APR. This would obviously be based on the marketability of the turbines, as well as the costs associated with their relocation at the end of the second lease period in November 2019 (or any agreed, extended lease period). This could be a swift exercise if APR has readily available alternative uses for the turbines. It may be, however, that the turbines are not readily marketable and are unlikely to be needed as other generation sources become available, minimising the future risk of ‘load-shedding’ affecting South Australian electricity consumers.

7.14. I have seen no evidence which estimates the marketability or resale value of the turbines, or which describes the timing, and likely effect or availability, of other electricity generation sources in the Australian electricity distribution network.12 As a result, I am not able to reliably advise on the financial implications of each step save the second, involving the retention and relocation of the turbines. The requisite analysis will bring to account the limited tenure available at the GMH site at Elizabeth, and the opportunity for longer tenure at the SA Water site at Lonsdale, together with the advantages of the proposed permanent site at Bolivar (including proximity to the electricity distribution network and the availability of a gas connection).

7.15. In short, the critical issue is whether these turbines are likely to be needed beyond the short-term. It is not appropriate to assume that there is a need for a permanent emergency electricity supply given the dynamics of the national electricity market and the large potential costs. If the best available advice is that a permanent emergency back-up is required, there may be opportunities to share the costs with APR Energy or another private operator. The long-term exposure of the State to load-shedding events is key. In my opinion it is necessary to better understand that risk before reaching any final decision about retaining the turbines or whether it is necessary for the State to commit between $187.5 million and $267.5 million to their relocation and long-term operation and maintenance. Context for the generator procurement process

8. As the result of what has been described by the Australian Energy Market Operator (AEMO)13 as the disorderly closure of coal fired electricity generators across Australia, warnings were issued about the potential for disruption in the supply of electricity in several states, most relevantly for my purposes, in Victoria and in South Australia.14 In

12 An interconnector is being built in NSW and a solar thermal plant is being constructed in Port Augusta, see the Treasury Minute dated 26 March 2018. 13 AEMO operates Australia's National Electricity Market (NEM), the interconnected power system in Australia’s eastern and south-eastern seaboard, and the Wholesale Electricity Market (WEM) and power system in Western Australia. See http://www.aemo.com.au/About-AEMO/AEMO-history. 14 See, by way of example, AEMO’s report: http://www.aemo.com.au//media/Files/Electricity/NEM/Planning_and_Forecasting/NTNDP/2016/Dec/2 016-NATIONAL-TRANSMISSION-NETWORK-DEVELOPMENT-PLAN.pdf.

particular, the withdrawal of the Hazelwood Power Station Victoria was believed to have created “an increased risk of system security issues” resulting in a “potential short fall of up to 500MW of generation”.

9. AEMO predicted potential short falls in the generation required to meet peak demand for electricity on days of extreme heat during the summer periods during 2017-2018 and 2018-2019, if not earlier.

10. On 28 September 2016 South Australia experienced a violent, once in fifty-year storm event. Gale force wind across the State and at least two tornadoes near Blyth were associated with 80,000 lightning strikes. Critical electricity transmission infrastructure was damaged. 23 pylons and 3 of the 4 interconnectors connecting Adelaide to the North and to the West of the State were damaged.15

11. The result was a cascading failure in the electricity transmission network and the State lost almost its entire electricity supply.

12. Despite attempts to restore power during the late afternoon, with much of the power in Adelaide being restored by 10pm, by the morning of Friday, 30 September 216 around 10,000 properties remained without power. Indeed, another 18,000 properties had lost power due to continuing storms. Power was eventually restored.16

13. In the hours and days following the September 2016 blackouts there was wide-spread political debate nationally and locally about ‘energy security’ and the extent to which ‘renewable energy’ was responsible.

14. Late on Tuesday, 27 December 2016 there were further blackouts. Again, severe storms caused damage to over 300 power lines and electricity power was lost to over 150,000 properties. By Thursday, 29 December 2016 over 11,000 properties remained without power. By Saturday, 31 December 2016 more than 1600 properties were without power.

15. 8 February 2017 was the midst of a heatwave in South Australia.

16. At around 6pm that day AEMO ordered that 30,000 customers in South Australia be “load-shed” because of what was later said to be “incorrectly forecast demand during the peak afternoon period”.17 AEMO ordered 100MW of load shedding.18 In fact,

15 The South Australian electricity power grid is operated by ElecraNet and connected to the national electricity market by two interconnectors into Victoria. These are the Heywood and Murray link interconnectors. 16 See the AEMO Final Report on the ‘SA region Black System event’: http://www.aemo.com.au/Media- Centre/AEMO-publishes-final-report-into-the-South-Australian-state-wide-power-outage. 17 News release of the Honourable Tom Koutsantonis MP, the former Treasurer and Minister for Mineral Resources and Energy (Energy Minister), 26 March 2017 18 Because electricity generation systems are not always able to meet peak demand requirements, overall demand for electricity must be lowered. This can be achieved by turning off service to some devices or by cutting supply voltage so as to prevent uncontrolled disruptions such as power outages. When confronted with these conditions “load shedding” can be achieved by implementing agreements with consumers to turn off equipment or by a system of planned, rolling blackouts.

200MW was cut.19 It was later said that this occurred despite available generation in the market. As well, due to problems with the software being used, SA Power Networks “erroneously load-shed 60,000 more customers than was necessary”.20

17. The result was that 90,000 properties in the South Australian market experienced “black-outs”.

18. In the wake of these black-outs there was yet further political debate.21

19. The following month the then State Government announced a $550 million plan, generally described as the “Energy Plan”.22 There were a number of aspects to that plan. Some included greater emphasis upon renewable energy. One aspect of that was a 150 megawatt solar thermal power plant based in Port Augusta. Discussions commenced with the Chief Executive of Tesla, Mr Elon Musk, regarding the construction of what was then claimed to be the world’s largest lithium-ion battery at Jamestown in South Australia.

20. The Energy Plan included two measures of relevance to this report.

21. The first was the construction of a government owned 250MW gas-fired power station to address “the medium to long term”. According to the then Energy Minister:23

This state-owned gas-fired power station will be able to be turned on by the state government and dispatched in emergency situations when the private market refuses to prevent load- shedding.

The gas generator is a key component of the state government’s plan to take charge of the state’s energy future.

...

19 ABC News, 16 February 2017, reporting upon a preliminary report published by AEMO. In that report AEMO had explained that a restriction to supply was ordered to prevent the risk of prolonged damage to infrastructure, and that the directive issued to ElectraNet shortly after 6pm was to reduce load by 100MW. In turn, ElectraNet instructed the local power distributer, SA Power Networks, to begin load shedding by switching off supply to designated areas. However, by 6.20pm 200MW had been switched off. AEMO gave a directive to restore power 27 minutes after its initial order. The requirement for load shedding was created by record power demand during heatwave conditions, outstripping available supply and putting pressure the Heywood and Murray link interconnectors, exceeding operating limits. AEMO’s report explained that at the time of peak demand, wind generation and thermal generation were lower than forecast, associated with forced power outages at the Torrens Island, Quarantine and Port Lincoln generators. SA Power Networks issued a statement that load shedding software had “kicked in” when the system was experiencing “some of the highest electricity demands ever recorded in the State”. An investigation was underway to determine why the load shedding software failed to operate correctly, as one aspect of a response to the Energy Minister’s criticism that AEMO had got its demand forecast wrong and failed to bring a second generation unit online at Pelican Point. 20 Energy Minister News Release, 26 March 2017 21 See for example, http://www.abc.net.au/news/2017-02-15/sa-power-aemo-report-into-rolling-blackouts- during-heatwave/8273836. 22 Aspects of the Energy Plan were embodied in the Emergency Management (Electricity Supply Emergencies) Amendment Bill 2017 23 Energy Minister News Release, 26 March 2017

This brand new gas generator will be the first state owned electricity infrastructure since the Liberals sold ETSA.

Through this plan we are building generation and storage capacity, using our own procurement to bring additional generation into the market and incentivising the production of more gas to be supplied to local power stations.

22. The second measure of relevance to this report, “to assist in managing short-term energy security risks”, was an additional (short-term) power generation facility. As it was later explained in the “Detailed Acquisition Plan” dated 6 April 2017:

It is likely that this short-term solution will be required for a period of up to two years (one plus one-year period with a right of termination after twelve months on sixty days’ notice). The provider will be asked to implement exit clauses to enable a short-term security measures to cease should the 250MW gas fire generation plant become available within the contract time frame.

23. In the wake of the 8 February 2017 black-outs, continued political debate about the need for and effectiveness of Federal action on energy policy was underscored by electricity price increases announced in South Australia during June 2017.24

24. As will be seen, the “purchase option” referred to in the First Term of Reference arises out of a variation to the arrangements made for short-term electricity generation. The requirements of procurement

25. Before examining the procurement of short-term electricity generation in more detail, it is appropriate to identify the applicable procurement requirements.

26. Broadly, the acquisition of goods and services is governed by the State Procurement Act 2004 and associated policies and guidelines, whereas expenditure on the construction of public infrastructure is addressed by the “Public Works Committee”, a standing committee of the South Australian Parliament, the powers and functions of which are laid down in the Parliamentary Committees Act 1991.

27. Whilst I shall return to the Public Works Committee’s ‘Final Report’, it is appropriate here to observe that its functions, consistent with s 12C of The Parliamentary Committees Act 1991, include inquiry into, considering and reporting upon any “public work” referred to it, including the necessity or advisability of constructing that public work.

28. The concept of a “public work” is defined in s 3 as including “any work that is proposed to be constructed where… the whole or a part of the cost of construction of the work is to be met from money provided or to be provided by Parliament or a State instrumentality… [or] the work is to be constructed by or on behalf of the Crown or a State instrumentality… [or] the work is to be constructed on land of the Crown or a State instrumentality”.

24 Energy Minister News Release, 10 June 2017

29. In addition, apart from the “present and prospective public value of the work” the “recurrent or whole of life costs associated with the work, including costs arising out of financial arrangements”, as well as the estimated net effect on the Consolidated Account must be considered.

30. The “project” was referred to the Public Works Committee by DPC. Despite that, the Public Works Committee was provided with a report by the Energy Minister.25 As will be seen, it seems likely that there was at least some confusion about the extent to which the “project” by early August 2017 entailed the construction of a “public work”. Certainly that had been in prospect when the State-owned permanent gas-fired plant was under consideration, but it was only ever a peripheral aspect of any acquisition of the APR Energy short-term generation turbines.

31. The exercise of the option to purchase - and the corresponding purchase, operation and maintenance of the turbines - were steps associated with the acquisition of goods and services, and more obviously under the oversight of the State Procurement Board.

32. By the “Procurement Authority and Governance Policy”:26

‘Procurement Authority’ is the authority to approve a proposed course of action, strategy or recommendation relating to procurement (i.e. acquisition plan or purchase recommendation) to a specified dollar amount as delegated to a public authority’s principal officer by the Board.

33. Under the State Procurement Act 2004 there is established a State Procurement Board,27 the functions of which include the facilitation of strategic procurement by public authorities by setting the strategic direction of procurement practices across government, and to give directions relating to the procurement operations of public authorities.28

34. When performing its functions, the Board is empowered to direct a “public authority” to furnish it with documents or other information.29 The procedures at meetings of the Board may be determined by the Board.30 In practice applications for the approval of procurements are made pursuant to guidelines published by the Board.

35. Public authorities, including each member or officer of that authority, are bound to comply with any applicable policy or guideline given by the Board, as well as any directions given by a responsible Minister on the advice or recommendation of the Board. A “prescribed public authority” is bound to comply with any directions given by the responsible Minister on the advice or recommendation of the Board.31 As a

25 Which was said to be “a little bit unusual”, Transcript of the Publics Work Committee “Installation of Hybrid Turbines as Long Term Back Up Power Plant” Thursday, 10 August 2017 at 8.50am, page 5. 26 The March 2018 Policy may be found here: http://www.spb.sa.gov.au/sites/default/files/Procurement%20Authority%20and%20Governance%20Polic y%20March%202018%20v%201.0_0.pdf. 27 State Procurement Act 2004, s 7. 28 State Procurement Act 2004, s 12(1)(a) and (d). 29 State Procurement Act 2004, s 12(2)(d). 30 State Procurement Act 2004, s 15(8) 31 State Procurement Act 2004, s 19

concomitant to these arrangements, the principal officer of a public authority is responsible for the efficient and cost-effective management of procurement operations of that authority subject to, and in accordance with, the policies or guidelines of the Board.32

36. A “public authority” is any unit or agency or instrumentality of the Crown, including any incorporated or unincorporated body, together with any person or body declared by regulation to be a public authority. The concept of a “prescribed public authority” is that person or body declared by regulations to be so for the purposes of the Act.33

37. DPC is regarded as a Tier 1 public authority with a procurement authority up to $15 million inclusive of GST.

38. It is appropriate to describe the committees or bodies created to implement the former Government’s Energy Plan, because various of the procurement decisions relevant to my investigation were conceived, developed and promoted from within these committees.

39. Soon after the then Government announced its Energy Plan in March 2017 an Energy Plan Implementation Committee (EPIC) was convened. Its members included senior officers from DPC, Dr Don Russell (Chair), from Treasury, the Under-Treasurer Mr David Reynolds, and from the Crown Solicitor’s Office, initially Ms Judy Hughes and then Mr Mike Wait SC (presumably after her Honour’s appointment to the Supreme Court).

40. Reporting to EPIC was an “Implementation Taskforce”, headed by the ‘Energy Plan Lead’. Terms of Reference for EPIC and the Energy Projects Leadership Team were signed in July 2017. Both highlighted the 200MW Temporary and 250MW Emergency Projects. Membership of the Implementation Taskforce included a Chief Procurement Officer and engineering, legal and financial advisors.

41. In addition, the South Australian Government and SA Power Networks formed a “Steering Committee” to facilitate discussions regarding the design, construction and commissioning of the Short-Term Generator, fortnightly or otherwise as agreed.34

42. Under the DPC ‘Procurement Governance Policy’ signed by Dr Russell on 23 October 2017 it is recorded that the Chief Executive DPC and the Chief Executive Treasury, had approved a combined Accredited Purchasing Unit (APU) to advise and support the Chief Executive in discharging responsibilities imposed by the State Procurement Act 2004.

32 State Procurement Act 2004, s 20(1). 33 State Procurement Act 2004, s 4 34 The “Steering Committee’ or ‘Joint Steering Committee’ had as its SA Power Networks members the CEO, CFO, General Managers for Network, Field Services and Corporate Strategy. The South Australian Government members were Mr Sam Crafter (Chief Economic Advisor, Office of the Premier) and Mr Jason Schell (Chief Procurement Officer, Department of Premier and Cabinet).

43. I have been provided with a “Procurement Matrix”. This appears to document the procurement practices followed by EPIC and the Implementation Taskforce. For projects above $15 million any ‘Acquisition Plan’ was required to be endorsed “by APU and approved by State Procurement Board”. Any market process was required to be a “Full competitive process”. Any ‘Purchase Recommendation’ likewise required endorsement “by APU and approved by State Procurement Board” (or its delegate). Any contract had to be approved by Cabinet.

44. Under the DPC and Treasury “Procurement Process Approvals Guideline” the approach described in the “Procurement Matrix” was set out in more detail.35 It is clear that procurement projects exceeding $15 million required the preparation of a detailed ‘Acquisition Plan’ and a detailed ‘Purchase Recommendation’, as well as an industry participation policy plan. Submission to and endorsement by the APU and Chief Executive was usually required ahead of State Procurement Board approval. In some cases there was facility for the delegation of a detailed purchase recommendation by the Board to the Chief Executive, DPC.

45. Ultimately, any procurement of goods or services relevant to my investigation primarily required State Procurement Board approval or delegation. Short-term electricity generation procurement

46. By letter dated 8 March 2017 Ms Nicolle Rantanen, the Presiding Member of the State Procurement Board, wrote to Dr Don Russell, Chief Executive of DPC, advising that on 8 March 2017 the Board had approved DPC:

Approaching the market for goods and or services related to creating greater certainty in South Australia’s electricity supply, prior to consideration of an acquisition plan as would normally be required under the Board’s policy framework.

Pursuant to s 12(1)d of the State Procurement Act 2004 (Act), the Board directed that DPC may carry out an alternative procurement process, whereby required planning documentation can be developed in tandem with a market approach.

47. It is noted in handwriting on the copy of the letter dated 8 March 2017 supplied to me that the letter was received by the Chief Executive’s office on 23 March 2017.

48. On 28 March 2017 Dr Russell wrote to Mr Sean Kelly, General Manager Corporate Strategy, SA Power Networks, regarding the engagement of SA Power Networks to assist in managing short-term energy security risks by procuring 200MW of additional temporary generation.

49. As Dr Russell explained it, the withdrawal of the Hazelwood Power Station Victoria created an increased risk of system security issues. Dr Russell cited advice that there was a potential shortfall of up to 500MW of generation required to meet peak demand on days of extreme heat during the 2018 and 2019 summer periods, or earlier.

35 I was supplied with Version 2.2: December 2017, but it was not suggested that the practices differed between June and November 2017.

50. Dr Russell advised that, given the short-term requirements to provide additional generation the 200MW system was required to be designed, constructed, commissioned and tested, performance verified including operation and maintenance agreements in place, by 1 December 2017.

51. As Dr Russell explained, the arrangement for the supply of 200MW of additional temporary generation would cease when the proposed 250MW gas-fired generation plant became available.

52. Dr Russell told Mr Kelly that the South Australian Government was seeking to manage the process in clearly defined stages and, as a first stage, he sought formal support to develop a functional specification and term sheet in partnership with DPC, followed by the parties entering into a contract to document in detail their agreement. It was Dr Russell’s intention that a second phase would involve SA Power Networks procuring the 200MW generation in accordance with that agreement.

53. On 7 April 2017 Mr Paul Williams, Chair, APU recommended to the Chief Executive DPC, Dr Russell, approval for an ‘Acquisition Plan’ for “Short-Term Electricity Generation” by way of a “Minute”. The ‘Acquisition Plan’ concerned the procurement of services for the construction, commissioning, testing and performance verification of a 200MW addition (short-term) power generation facility, intended to be completed by 1 December 2017.

54. The Minute recorded that “market research” had identified that the only entity capable of delivering services within the short time frame required was SA Power Networks and, in consequence, “the proposed market approach is direct negotiation with SA Power Networks”.

55. It was acknowledged that commencing negotiations before obtaining approval of the acquisition plan was not in compliance with the requirements of the State Procurement Board “Acquisition Planning Guideline”. This specified that approval was required before approaching the market. However, the Board had in March 2017 previously directed that DPC could carry out alternative procurement processes involving the development of planning documentation “in tandem with the market approach”.36

56. The Minute explained that the contract would be prepared by the Crown Solicitor’s Office for “a maximum term of two (2) years. The estimated total value of the proposed acquisition is $112 million (GST inclusive) for the maximum contractual term”.

57. The Minute concluded that a submission approved by Cabinet on 9 March 2017, “Energy Policy ‘South Australian Power for South Australians’”, had authorised provision for the costs associated with various measures, including the 200MW

36 The Board requested that DPC complete all related procurement processes in accordance with “its policy framework and the objects of the Act” and provide supporting documentation “at the earliest opportunity”; see the ‘Detailed Acquisition Plan’ - “Short-Term Electricity Generation” dated 6 April 2017, page 7

additional (short-term) power generation, which would be included in the 2017/2018 budget “as part of the budget process”.

58. Dr Russell endorsed the recommendation on the same day, on 7 April 2017.

59. The ‘Detailed Acquisition Plan’ was provided to the State Procurement Board with a brief covering letter dated 7 April 2017, essentially reiterating the information just described. Dr Russell asked the Board to “delegate to me authority to approve the purchase recommendation”.

60. The ‘Detailed Acquisition Plan’ recognised that the procurement process was required to comply with the requirements of the State Procurement Act 2004 and the Board’s policies and guidelines with emphasis upon:37

60.1. obtaining value in the expenditure of public money;

60.2. providing for the ethical and fair treatment of participants;

60.3. ensuring probity, accountability and transparency in procurement operations.

61. The ‘Detailed Acquisition Plan’ described the construction and commissioning of the 200MW additional (short-term) power generation as “an urgent requirement” to manage “short-term energy risks” within the South Australian network given that the South Australian Government neither owned nor managed electricity generation or distribution networks and “has no skills or capability to deliver the requirements and it is restricted by the electricity regulations from doing so”.

62. Because South Australia was, it was explained, a “very limited market” there was a limited number of suppliers capable of constructing and commissioning power generation as well as connecting this equipment and distributing the electricity through the South Australian network “within the required time frame”.

63. It was proposed to provide a number of suppliers within the electricity generation market with the opportunity to compete for the work required to provide diesel generation equipment with the potential for duel gas/diesel hybrid generation. Because it was necessary to connect the generation equipment to the national electricity grid, a process that can take up to twelve months, it was recognised that there were difficulties meeting the 1 December 2017 time frame and so a network service provider was thought best placed to procure the infrastructure so as to ensure availability to “meet peak demand on days of extreme heat from 1 December 2017”.

64. Whilst ElectraNet was considered, it being a transmission provider and responsible for the majority of transmission network infrastructure in South Australia which is connected to the national electricity grid, only SA Power Networks confirmed that it had the capacity to source and deploy the relevant generation before 1 December 2017.

37 The legislation and policy said to be relevant to the “this procurement” were the Treasurer’s Instructions, Industry Participation Policy, DPC Circular 27, Work Health and Safety Act 2012, South Australia’s Strategic Plan and DPC Procurement Governance Policy.

SA Power Networks was described as the licenced provider of distribution services to the majority of South Australia and solely responsible for the South Australian distribution network infrastructure connected to the national electricity grid. As well, “SA Power Network’s 66Kv [sic, kV] distribution network” was “identified as the most suitable method of connection to overcome any network stability issues”.

65. Whilst a range of regional providers (who had been granted transmission or distribution licences or exemptions) were considered, none were viable given the remoteness of their operations and the necessity for connection points close to existing transmission facilities.

66. The ‘Detailed Acquisition Plan’ identified that because the goods and services contract would not be entered into on a commercial basis, but rather on a “State benefit” basis, there was limited opportunity for SA Power Networks to generate commercial profits and so an appropriate limitation of supplier liability would likely form part of the arrangements. As well, separate insurance arrangements would be required.

67. A report supplied to the State Procurement Board on 12 April 2017 to assist its review of the ‘Detailed Acquisition Plan’ recorded that the Board’s approval to DPC on 8 March 2017 authorising the development of planning documents together with a market approach was necessitated by what was described as “extreme urgency” represented in the following risks:

67.1. insufficient capacity through or failure of the interconnector;

67.2. low wind generation;

67.3. issues at existing generation plants.

68. The procurement was assessed as “high risk” and it was recorded that a specialist probity advisor from BDO Advisory Pty Ltd had been appointed to provide advice and services to DPC for all procurement processes related to the SA Energy Plan. It was recommended that the Chief Executive of DPC be nominated to approve any purchase recommendation arising out of the implementation of the ‘Acquisition Plan’ unless there was a “material deviation/variation”.

69. The State Procurement Board held a special meeting on 13 April 2017 at which it approved the ‘Detailed Acquisition Plan’ from DPC for the provision of 200MW short- term electricity generation, confining the approval to any goods or services component. In its letter sent to the Chief Executive, DPC the same day, it was noted that the proposed contract term was for a period of only one year with the option to extend for a further year and the total anticipated value of the contract was $112 million.

70. The Chief Executive of DPC (or his delegate) was nominated to approve any purchase recommendation arising out of the implementation of the ‘Detailed Acquisition Plan’ and no further reference to the Board was required unless there was a “material deviation/variation”.

71. Just over two months later, on 27 June 2017 a ‘Detailed Purchase Recommendation’ was prepared by the Acting Chair, APU and supplied to Dr Don Russell, Chief Executive, DPC by a Minute dated 29 June 2017.

72. The ‘Detailed Purchase Recommendation’ recorded three distinct stages of the negotiation process. The first was an initial engagement with SA Power Networks to develop the functional specification and term sheet, the second was for SA Power Networks to undertake a market process to procure 200MW of additional power generation and associated approvals, and the third and final stage involved the negotiation of appropriate contractual terms and conditions with SA Power Networks for the provision of the additional power generation.

73. The market process had commenced with SA Power Networks issuing a request for information to fifteen selected suppliers on 7 April 2017. Five responded and three suppliers were short listed. Power Rental OpCo Australia LLC (APR) was the highest rated supplier across the valuation criteria prepared for the purposes of the market process. APR suggested 9 turbines with a minimum capacity at all times and in all conditions of 170MW.

74. APR also suggested three options for DPC to consider: the first option was a lease only arrangement at a cost of $133.5 million, the second option involved acquisition with APR operating and maintaining the generators for 25 months at a cost of $302.6 million, and the third option involved a lease for 13 months with purchase in the thirteenth month and a further 12 months of operation by APR at a cost of $312.3 million.

75. SA Power Networks recommended option three.

76. To this point there is no evidence that any other supplier had considered the possible inclusion of an option to purchase in what were assumed to be short-term lease arrangements. Certainly, there is no record of any competitive process by which the APR Energy purchase cost was tested.

77. The ‘Detailed Purchase Recommendation’ set out a table regarding the cost of the recommended, option three. It appears to be the first formal costing of a purchase option:38

Concept phase costs (SA Power Networks and $1,200,000.00 Consultants) Development phase APR costs-transport, setup $15,217,000.00 and commissioning costs Development phase other costs-set up and $10,605,107.00 commissioning costs (site preparation, SA Power Networks, site rental, licence and approvals)

38 ‘Detailed Purchase Recommendation’ - “Short-Term Electricity Generation” dated 27 June 2017, page 10.

Network connection costs at two sites $15,000,000.00 APR lease costs for thirteen months $62,369,875.00 Fuel costs $3,070,883.00 Other costs for first thirteen months (SA Power $2,040,565.00 Networks, site rentals, etc) Decommissioning (APR costs) $6,294,739.00 Contingency APR (including any need for $1,500,000.00 noise attenuation) Less value of reusable connection assets -$2,000,000.00 TOTAL: $115,298,159.00 Purchase price at 13 months $227,162,297.00 TOTAL PLUS PURCHASE OPTION: $342,460,456.00

78. It was noted that DPC would have the option to extend the SA Power Networks contract for a further twelve-month period at an estimated cost of $62 million (essentially the lease cost).

79. It is then recorded that the Joint Steering Committee (comprising officers from the Department of the Premier and Cabinet and SA Power Networks) had been created to oversee implementation of the Energy Plan. The outcome of the market process was presented to that Joint Steering Committee on 9 June 2017. Significantly, it is then recorded (page 11):

DPC accepted the recommendation in the report that DPC lease TM500 gas turbines and all step-up transformers and associated balance of plant for a period of thirteen months with DPC exercising a right to purchase the generators on 1 December 2018.

80. This appears to be the first reference to any actual exercise of a right to purchase.

81. It is appropriate at this moment to pause and digress to consider the report referred to in the ‘Detailed Purchase Recommendation’.

82. I have been provided with the “SAG Temporary Generation Concept Report” dated 9 June 2017. That appears to be the report just mentioned. By that report the General Manager Corporate Strategy for SA Power Networks recommended to the Joint Steering Committee that the 9 TM2500 gas turbines and all set up transformers and associated balance of plant be leased for a period of 13 months with the South Australian Government exercising a right to purchase the generators on 1 December 2018.

83. The total project costs were summarised in a table which is identical to that earlier set out above and which tallies $342,460,456.00. This “recommended solution” assumed civil works at Lonsdale and Elizabeth (page 2). Amongst the key commercial elements was a “strong SAG preference for commissioning by 1 November 2017” (page 3). The requirements included the essential attributes of the temporary generation facility, identification of appropriate site locations (utilising maps which would later be provided to the Public Works Committee) and a report regarding commercial negotiations with short listed suppliers during May 2017 (page 9).

84. The SAG Temporary Generation Concept Report then described AEMO’s requirements, which were said to be compliance with technical standards as well as registration of the generators in accordance with market rules (page 11). It is said that AEMO officials expressed a strong preference for the installation of gas turbines because it was “likely to be the best available to ride through system disturbances and has the least risk of resulting in a cascading black system event”. The requirements of the Environment Protection Agency as well as the Australian Energy Regulator were also described.

85. In my view, it is significant that there does not appear to be any independent expert report or other evidence provided to or considered by the Joint Steering Committee addressing the prospect of energy security risk beyond the proposed lease periods.

86. In particular, the SAG Temporary Generation Concept Report of 9 June 2017, whilst recommending an incurring of the purchase price at 13 months of $227 million, does not explain the likely environment for the operation of the turbines in 5 years, 10 years or 25 years into the future. No reference is made to the national electricity market or the need for a State-owned permanent plant.

87. I now return to the ‘Detailed Purchase Recommendation’: it identified a raft of required contractual negotiations. These included (page 11):

87.1. A short-term capacity contract between DPC and SA Power Networks for the supply of temporary generating services (noting requirement for no risks for SA Power Networks);

87.2. a short-term capacity supply contract between SA Power Networks and APR for the supply and operation of the temporary generators with appropriate incentives and penalties for delivery and performance;

87.3. a tripartite agreement between DPC, SA Power Networks and APR to ensure liquidated damages under the SA Power Networks – APR contract remain enforceable;

87.4. a purchase contract between DPC and APR Energy Holdings Ltd for the generators, step up transformers and associated balance of plant;

87.5. an operations and maintenance contract between DPC and APR to cover the possibility that SAG requests APR to operate the generators for a period after SAG purchases the generators;39

87.6. site leases with SA Water and GMH;40

39 SAG appears to be a reference to South Australian Government 40 These being the owners or occupiers of the sites at which the temporary facilities were to be constructed.

87.7. various contracts between SA Power Networks and third parties to undertake site civil works and to provide consulting services for procurement, environmental and technical modelling services. These are with contractors on SA Power Networks various service panels and standard panel contract agreements are in place. These do not include any performance criteria, such as liquidated damages, but include standard liability and indemnity requirements, which SA Power Networks will pass through to DPC as and when applicable.

88. As part of the contractual negotiations, various ‘key commercial elements’ were identified. In addition, there were ‘key operational arrangements’, including the necessity for the generators to be capable of being remotely started from the SA Power Network operation centre, as well as APR having both sites manned at all times to ensure safety, security and availability of power in the event of any failure in the remote start-up capability.

89. The ‘Detailed Purchase Recommendation’ then explained that contracts had already been developed by the Crown Solicitor’s Office, together with external legal resources. The key elements were identified as being:41

The maximum term of the contracts will be twenty-five months (thirteen months plus twelve months with a right of termination after the initial term on sixty days’ notice) at an estimated cost of $177,298,159.00 (GST inclusive).

... the estimated value of the option to purchase the plant and equipment is $227,162,297.00 (GST inclusive). The estimated total value of the proposed contract plus the purchase option is $404,460,456.00 (GST inclusive)

The contracts will commence on 1 July 2017 for the initial stage to purchase, install and connect to the electricity grid the additional power generation. The additional power generation must be operational on or before 1 December 2017.

90. The ‘Detailed Purchase Recommendation’ records that a Cabinet submission “SA Energy Plan – a solution for our future energy needs” was approved by Cabinet on 21 June 2017, authorising expenditure of $62.4 million for the initial thirteen-month lease for short-term generation with APR and $52.9 million for the costs of development, set up, licencing, expected operation commissioning and decommissioning, noting that:

…the option existed for an agreed purchase price of $227.2 million for the plant and equipment after the initial thirteen-month period. Should the option to purchase be exercised, a further cabinet submission is required for expenditure approval.

91. The ‘Detailed Purchase Recommendation’ pointed out that due diligence by SA Power Networks regarding APR’s financial assessment was rated “unsatisfactory” based on 2015 audited accounts, but “satisfactory” based on unaudited 2016 accounts due to significant private equity funds by which the parent recapitalised the business during 2016. In consequence, liquidated damages were thought to be of little value. Letters of comfort were obtained from General Electric, APR’s major supplier, and Fairfax

41 ‘Detailed Purchase Recommendation’ - “Short-Term Electricity Generation”, 27 June 2017, page 13.

Financial Holdings, APR’s major investor, to provide reassurance regarding the capacity of APR to perform.

92. As I have explained, the ‘Detailed Purchase Recommendation’ was supplied to the Chief Executive on 29 June 2017 and considered and approved by him on the same day. Undoubtedly this was done in the exercise of the delegated authority conferred by the Board on 13 April 2017.

93. And, also on 29 June 2017, the Manager, Procurement sent a Minute to the Executive Director, Energy Plan Implementation Taskforce, advising him of the approval.

94. However it is necessary to emphasise that the relevant purchase recommendation endorsed by the Accredited Purchasing Unit and approved by the Chief Executive was confined to the engagement of SA Power Networks for a maximum period of twenty- five months at an estimated total cost of $177,298,159.00 (GST inclusive). The Accredited Purchasing Unit merely noted that the estimated value of the option to purchase was $227,162, 297 (GST inclusive) and that “the estimated total value of the proposed contract plus the purchase option is $404,464,456.00 (GST inclusive)”.

95. In addition, and as I shall later explain, there can be no serious debate about the proposition that what was being considered under the exercise of the Board’s delegated authority was materially very different from the proposed contract term for a period of only one year with the option to extend for a further year, with a total anticipated value of $112 million, approved by the Board on 13 April 2017. Not only was the contract cost $65 million higher, but the arrangements approved under delegation in June 2017 included the new concept of an option to purchase with a potential overall exposure exceeding $404 million.

96. As mentioned, Cabinet met on about 21 June 2017 to consider and approve the contractual arrangements with APM which incorporated the option to purchase. I have asked for a copy of the Cabinet submission setting out the financial and other implications associated with that decision making. As I have earlier explained, I have not obtained access to that submission.

97. On 6 July 2017 the Energy Minister entered into a contract with SA Power Networks entitled the “Short-Term Capacity Contract” embodying the terms on which SA Power Networks would design, build and operate one or more short-term power generation plants having a minimum aggregate capacity of 200MW. On the same day SA Power Networks and APR entered into a “Short-Term Capacity Supply Contract” under which the arrangements by which SA Power Networks would procure the required generators from APR were documented.

98. Later in July 2017, Aurecon provided advice on the prospects and preliminary costings associated with retaining and relocating the turbines. I will consider Aurecon’s work shortly.

99. Following Aurecon’s report, on 1 August 2017 the then Premier and Energy Minister announced that the long-term back up power plant would be delivered ahead of summer:42

Rather than just procure temporary generators, the government will purchase 9 new GE TM2500 aero-derivative turbines, providing up to 276MW of generation to the grid when required.

The hybrid turbine power plant will initially be installed at 2 locations, the Adelaide desalination plant at Lonsdale and at the General Motors Holden site at Elizabeth, operating on diesel fuel over the next 2 summers, before being relocated to a permanent location as a state-owned power plant operating on gas.

100. It was announced that the total cost of the procurement, installation and relocation of the power plant would be $411.5 million over the next 4 years, to be met within the overall $550 million budget of the Energy Plan. I am unsure from where these estimates came, but they are almost identical to advice later recorded in an October 2017 Minute.43

101. The News Release advised that the power plant was being supplied by APR Energy “following a competitive tendering process conducted by SA Power Networks” and would have a lifespan of around 25 years.

102. As has been seen, whilst there was a competitive tendering process in connection with the supply of short-term electricity generation, that did not involve competition over the cost of acquiring what was proposed as part of that process. Only APR offered that. Rather, the cost of permanent power generation (in which process APR Energy did not feature) was addressed by a separate, parallel process and subject to different specifications.

103. On 7 August 2017 the Energy Minister entered into a “Call Option Deed for Electricity Generation Assets” with APR Energy. By this agreement APR granted the Minister (undoubtedly on behalf of the South Australian Government) an option to purchase the generation assets. Schedule 2 to that deed comprised the relevant Exercise Notice and Schedule 3 comprised the Asset Sale Contract.

104. On 11 August 2017 Mr Sean Kelly, General Manager Corporate Strategy of SA Power Networks, wrote to Mr Bryan Scruby, Project Manager Emergency Power Plant Project within DPC, confirming that SA Power Networks did not consent to the public disclosure of the Short-Term Capacity Contract because it contained “confidential business information”. Mr Kelly sought confirmation “via return correspondence” that the Short-Term Capacity Contract would not be disclosed to the public. I have not seen any correspondence in reply from Mr Scruby, or anyone else from DPC.

105. It is significant, in my view, that at the time decision-making was announced concerning the “State relocation option” for the acquisition of the 9 GE TM2500 gas

42 News release, the then Premier and Energy Minster dated 1 August 2017. 43 Minute from Mr Sam Crafter, Executive Director, Energy Plan Implantation to the DPC Accredited Purchasing Unit dated 19 October 2017, page 2.

turbines from APR Energy, no further or contemporaneous consideration appears to have been given to the necessity for a state owned permanent emergency electricity generator. Rather, the necessity for this permanent facility appears to have been assumed. The source for that assumption appears to be the SA Energy Plan announced by the then State Government on 4 March 2017.44 The Aurecon draft concept and cost estimate

106. In a report entitled “Emergency Gas Generation Project – Permanent Facility Cost Study” dated 20 July 2017 Aurecon provided a ‘high-level concept’ for the emergency gas generation project based on relocating equipment from the temporary facility sites to create a permanent facility site. The purpose of the study included developing a Cost Estimate for the permanent facility based on relocation with an accuracy of ‘plus or minus 30%’.

107. Under the “Executive Summary” (page 3) the Estimated Capital Cost to create a permanent facility site based on relocating the 9 gas turbines supplied under the Temporary Power Contract was approximated at $329 million. This included the purchase price of the gas turbines. Opportunities to reduce that cost were identified as including co-locating with another project, reducing the level of permanency of the site through “value engineering”, or by relocating a reduced number of gas turbines.

108. The Overview of the Concept (from page 4) assumed a “standalone site” which could be developed as a “permanent installation suitable for the operation and maintenance of the facility over its life of 25 years”. It was explained that the design philosophy and cost had been developed on a permanent basis for comparison with a separate invitation to supply for the Gas-Fired Electricity Generation Plant. The Overview also explained that the 9 TM2500 trailer mounted gas turbines would require modification to enable duel fuel operation, utilising both diesel and gas, as well as including arrangements for water injection for emissions control for both gas and diesel operation (page 5).

109. The permanent site would include all necessary new balance of plant equipment to augment that available from the Temporary Generation Contract so as to form a complete permanent facility. That would include a grid connection to the 275kV network, a gas connection to the gas network, liquid fuel unloading, storage and forwarding and all other required balance of plant for the facility (page 5).

110. Under the “Relocation approach” the Aurecon report explained that the proposal was to relocate the gas turbines in a staged manor to preserve emergency generation capacity whilst the permanent facility was finalised and commissioned. This would entail relocating one site at a time (page 6). A draft timeline was provided (page 7) and the “Scope of works” were explained in some details (from page 8). An initial site layout was provided, as were instructions for the required electrical connections.

111. Costings arriving at a total of $329 million were provided in some detail (page 14).

44 See, by way of example, the “Part A: Invitation for the Supply of a Gas-fired Electricity Generation Plant, Expression of Interest”, bearing an Opening Date of Tuesday, 28 March 2017.

112. Under Risks and Opportunities (Costing) the risks were said to be “additional costs... incurred due to either the site conditions or additional equipment”. Opportunities for reducing costing were also identified. The closest the report came to identifying any risks associated with the facility not being required in the future was the following (page 15):

Level of permanence: Depending of [sic on] the level of permanence (for example planned operating period of 5 years compared to 25 years), some cost savings could be realised by reducing the scope or level of utility of the plant.

113. Later, Aurecon provided a further report dated 18 October 2017 “Permanent Emergency Generation Facility, Relocation Study – Temporary Generation Plant” which recommended Bolivar as the preferred site for the relocation of the 9 temporary generation units on a permanent basis. Nonetheless, at page 2 and following of that report, Aurecon identified a number of alternatives to a single permanent site at Bolivar.

114. One alternative (page 30, paragraph 3.5.2) was to move the 5 units at the GMH site at Elizabeth to Bolivar and keep units at the SA Water site at Lonsdale. As part of this alternative, Aurecon advised that the State could consider “leaving units at Lonsdale for a shorter term say another 3-5 years and only move the 5 units from GMH to the preferred site at Bolivar initially”:

Potentially in the medium term, the State may not need the emergency generation facility pending the state of the South Australian Electricity Network and implementation of other generation and storage support.

However, the Lonsdale site would require a gas-fuel solution such as LPG if it was to be considered further as gas operation is one of the State’s requirements for this project.

115. The specified design life of 25 years considered by Aurecon was confined to the durability of the infrastructure elements. No analysis of any predicted or likely developments in technology or the Australian electricity generation market appears to have been considered or available. State owned gas-fired electricity generation plant

116. In parallel with arrangements for short-term electricity generation, arrangements were being made for the construction of a State-owned gas-fired electricity generation plant.

117. This was a separate and distinct process, with its own evaluation, evaluation report, preliminary evaluation report and procurement processes. It is unnecessary for the purposes of my report to describe these in detail. It is sufficient to note the outcome of the tender process which comprised an expression of interest process between May and June 2017, and a detailed evaluation phase during July 2017 which was interrupted

when it was recognised that it was preferable to proceed with a variation to the short- term electricity generation proposal. In particular:45

117.1. a Cabinet paper was apparently tabled at the Cabinet meeting on 27 July 2017 recommending that the tender process be discontinued in favour of purchasing the GE TM2500 units under the agreement of SA Power Networks and APR Energy. The decision-making was supported by a “Whole of Life Cost Comparison” Table prepared by PwC, to which I shall return in a moment;

117.2. on 1 August 2017 (the same day as the then Premier and Energy Minister made a joint News Release) notices were issued to each of the expression of interest and invitation to supply tenderers advising that the State had decided to discontinue that process without proceeding to a contract.

118. It was later explained that the total cost of procurement, installation and relocation of the power plant being developed for short-term electricity generation was $411.5 million over four years, which would be “met within the overall $550 million budget of the energy plan”.46 In October 2017 it was recommended that the APU note that, following detailed evaluation “the State decided to discontinue the tender process in favour of pursuing the purchase option under the short-term capacity contract”.

119. I earlier mentioned the PwC Whole of Life Cost Comparison. That showed that an estimate of the present cost of the state-owned gas-fired electricity generation plant was expected to lie in the range, broadly, $402 million to $474 million. By comparison, a variation to the short-term electricity generation model, together with relocation, was estimated to have a present cost of around $327 million.

120. This is obviously different to the “total cost of the procurement installation and relocation of the power plant” of $411.5 million announced on 1 August 2017 by the then Premier and Energy Minister in their joint News Release. The reason for the difference is unclear. The probabilities are that the PwC Whole of Life Cost Comparison did not sufficiently address the likely long-term costs associated with operation and maintenance of the permanent facility over a period of up to 25 years.

121. What is clear is that the PwC work was relied on to demonstrate that around $75 million in costs could be saved by pursuing a variation to the short-term electricity generation model, rather than the original plan for a State-owned gas-fired permanent plant. The Public Works Committee

122. Some of these matters were foreshadowed in a report to the Public Works Committee from the then Energy Minister, dated 2 August 2017.

45 Minute from Mr Sam Crafter, Executive Director, Energy Plan Implantation to the DPC Accredited Purchasing Unit dated 19 October 2017. 46 Minute from Mr Sam Crafter, Executive Director, Energy Plan Implantation to the DPC Accredited Purchasing Unit dated 19 October 2017.

123. In that report the arrangements with SA Power Networks and APR for short-term generation were described as confined to a thirteen-month plant and equipment lease which could be extended for up to twelve months, if required. It was noted that APR included in its bid an offer for the State Government to buy the generators and associated equipment after the initial thirteen-month operating lease period “or at any time up to the end of the twelve-month operating lease extension”. The report went on to record that, in connection with the tender for the permanent gas fired generation facility:

Bids were analysed against an independent study and estimate of a buy, convert and relocate to a green field site option. The study resulted in a $75 million favourable net present cost for the buy, convert and relocation option...

As a result, the...permanent facility procurement process has been terminated and the government has the option of purchasing the 9 TM2500 generators from APR.

124. This may be an indirect reference to the Aurecon and PwC work to which I have already referred. The report explained that the generators would initially be located at the SA Water Lonsdale desalination plant as well as at the Elizabeth GMH site, with development approvals having been expedited by the inclusion of the sites into schedule 14 of the Development Regulations 2008 under s 49(3) of the Development Act 1993, removing any requirement for consultation with other agencies (albeit that consultations had already commenced).

125. The report announced that a more detailed study of the relocation options to a permanent site would be planned to determine “the best value”.

126. The Energy Minister’s report was considered in the Public Works Committee hearing on 10 August 2017.

127. At that hearing representatives from the officers in DPC responsible for the “Energy Plan” provided further information. Quite apart from the public hearing, information was conveyed “in camera” about which, naturally enough, there is no record.

128. In the course of a presentation to the Committee, Mr Crafter from DPC identified, as a matter of context, the forecast made in the AEMO Energy Supply Outlook Report regarding the need for additional supply over the “coming two summers” in South Australia. Mr Crafter explained:47

SA Power Networks has a subcontract for the installation, operation and maintenance with APR Energy, they have been selected for their technology, their proven installation capability, access to equipment and competitive pricing. The purchase option that the government has is to direct with APR Energy, and it will be operational by 1 December.

Just to be clear about the operation of this generation, it is not intended that this generation will operate within the market as a competitor in the market. The purpose of the emergency generation is to avoid rotational load-shedding in South Australia. That will only be used in the last resort emergency scenario, and it will only be initiated by either AEMO, the

47 Transcript of the Publics Work Committee “Installation of Hybrid Turbines as Long Term Back Up Power Plant” Thursday, 10 August 2017 at 8.50am, page 2.

Australian Energy Market Operator, or at the direction of the Minister under the arrangements the Minister has.

129. Mr Crafter went on to explain that, in consultation with SA Power Networks, it had become clear that two sites would be needed, and consideration had been given to a permanent location as well. One of the difficulties with the two temporary sites was the absence of gas connection. Mr Crafter emphasised the very tight timeframes involved to proceed with the procurement process, have the generators shipped and arrive in Adelaide, and ensure that the civil works were ready so that the generators could be shifted to site, commissioned, pre-commissioned, tested and operational by 1 December 2017.

130. An AEMO approval process would also be required during commissioning.

131. The Public Works Committee was told that diesel would be used in the short-term, but after relocation to a permanent facility, “where you would bring all the generators into one site, which has gas access. We would be looking to do that after the second summer period”.48 The Committee was told that what had become clear through the process of developing the permanent and temporary schemes was that “similar types of generation” were involved, and that they were “working to be able to relocate... after that ....period to a permanent site with a gas location”.49

132. When asked about the independent study which suggested a $75 million favourable net present cost in connection with relocating the short-term supply generation facilities (which I have inferred may be either or both of the Aurecon and PwC reports), Mr Crafter emphasised the necessity for discussion about that to be held “in camera”.50

133. There was questioning about whether these arrangements would affect electricity prices and job creation. It was emphasised that the facilities were solely designed to meet emergency needs in the event of load-shedding. The committee was told that there were around 2,200 similar units world-wide and that there were some examples of their use permanently.51

134. The Final Report of the Public Works Committee was published on 15 August 2017, along with a minority report.52

48 Transcript of the Publics Work Committee “Installation of Hybrid Turbines as Long Term Back Up Power Plant” Thursday, 10 August 2017 at 8.50am, page 10. 49 Transcript of the Publics Work Committee “Installation of Hybrid Turbines as Long Term Back Up Power Plant” Thursday, 10 August 2017 at 8.50am, page 10 and 12. 50 Transcript of the Publics Work Committee “Installation of Hybrid Turbines as Long Term Back Up Power Plant” Thursday, 10 August 2017 at 8.50am, page 10. 51 Transcript of the Publics Work Committee “Installation of Hybrid Turbines as Long Term Back Up Power Plant” Thursday, 10 August 2017 at 8.50am, page 11-12. 52 Final report “Installation of Hybrid Turbines as Long Term Back Up Power Plant” 575th report of the Public Works Committee, Second Session, 53rd Parliament dated 15 August 2017 signed by the Honourable Michael Atkinson, Speaker and published pursuant to s17 of the Parliamentary Committees Act 1991.

135. Within Part One of the Final Report the Committee required DPC to notify it “immediately in writing should there be substantial changes to the nature of the project or the evidence provided” as well as to “provide an explanation of any expenditure beyond the estimated costs quoted in this report”.53

136. It is not possible to know whether that requirement has been complied with without knowing what was revealed “in camera”. I cannot say, for example, whether the Committee was given the impression that the “project” was likely to cost $327 million (as PwC calculated, and as is suggested by the $75 million ‘saving’)54 or $404 million (as APU was asked to note on 29 June 2017) or $411.5 million (as was announced by the then Premier and Energy Minister on 1 August 2017).

137. As part of the Project Background it was recorded that the then Government of South Australia had announced its Energy Plan in March 2017 with six key components:

137.1. Battery storage and renewable technology fund – a battery built in South Australia to restore renewable energy and add stability to suppliers as part of a new $150 million renewable technology fund.

137.2. More generation more competition – the Government to use its bulk buying power to attract new electricity generation to increase competition and put downward pressure on prices;

137.3. State owned gas power plant – build a Government owned gas power plant to provide standby, backup power available to South Australia in emergencies, including load-shedding events.

137.4. South Australian gas incentives – incentives to source more gas for use in South Australia.

137.5. Local control over the national market – the Government will legislate to give the South Australian Minister for Mineral Resources and Energy direction over the market.

137.6. Energy security target - a new target to increase South Australia’s “energy self reliance”.

138. It was recorded that, to enable backup power generation to be installed and available for the summer of 2017, a backup generation plant needed to be established at two interim sites until a more permanent backup plant location could be established at a site with access to gas connection.

139. Under Part Two it was recorded that investigations were underway to identify a permanent location for the backup power plant with access to gas connection and that

53 Final Report, page 3. 54 The Aurecon preliminary estimate of $329 million in July 2017 is not markedly different.

the generators would be relocated after the 2018-2019 summer. It was then formally noted that:55

As part of the agreement with APR Energy there is the option to purchase the nine generators at the end of the thirteen-month lease period but before the expiry of twenty-five months from the commencement of the lease. This is currently the government’s preferred option.

140. Under Part Four it was explained that part of the rational for proceeding with APR Energy was that it provided the lowest cost for a thirteen-month lease period and AEMO had indicated a strong preference for a gas turbine solution, as opposed to reciprocating engines. Whilst this section of the report noted the $75 million favourable net present cost associated with the buying, conversion and relocation of the APR turbines, curiously there is no suggestion of a decision having yet been made despite the announcement in the joint News Release on 1 August 2017.

141. As part of this aspect of the report the “Public Value” was described by reference to the Government’s Energy Plan, the need to mitigate the effects of load-shedding and the necessity for an urgent, temporary solution whilst “a more permanent back-up power plant is being pursued”.

142. The Committee described the devasting impact of load-shedding and the losses associated with the extended power outage in September 2016 were said to have been “estimated at around $367 million ... [with] consequent loss of reputation and impact to business investment”.

143. As for the Whole of Life Project Costs, these were not provided “due to commercial arrangements”, but were said to be within the $550 million budget allocation. Again, it may be that this is a reference to either or both of the Aurecon and the PwC work.

144. It was recorded that the “the intent is to establish a new backup facility after the summer of 2018-2019”.56

145. By Part Five, the Public Works Committee recommended the proposed public work.

146. The minority report prepared by the then members of the opposition expressed concerns, including about the absence of transparency concerning the full potential costs of the plan. They were unable to endorse the committee’s report.

147. At the time of the deliberations by the Public Works Committee the generators were in transit to Adelaide.57 Developments in November 2017

148. By late November 2017 the temporary facilities were constructed and in place.

55 Final report, page 5. 56 Final report, page 13. 57 Transcript of the Publics Work Committee “Installation of Hybrid Turbines as Long Term Back Up Power Plant” Thursday, 10 August 2017 at 8.50am, page 7.

149. I earlier mentioned EPIC. I have been supplied with extracts from minutes of its meetings on 14 November, 21 November and 28 November 2017.

150. Portions of the minutes are redacted. I was advised that the redactions were intended to remove references to topics which were not relevant to my investigation.

151. On 14 November 2017 EPIC considered what was described as the “permanent generator”. The minutes record a discussion about the timing for “triggering purchase and for actions to commence relocation work”.58 The discussion centred on various options and timing implications and “other risks and benefits”. The discussion ranged between “purchasing now, purchasing later, not purchasing”, and “what a commitment now would mean for an incoming government”. It was apparently agreed to progress a Cabinet submission to the Treasurer which provided an assessment of the various options for Cabinet to make an informed decision.

152. Under the heading “Conclusions” the “generator submission” was to be “revised”. Under the “action items” the revision to the generator submission to reflect the options was to be prepared the following day.

153. At the meeting of EPIC on 21 November 2017 there was a discussion about what was described as a “Cabinet update”.59

154. The minutes record that Mr Sam Crafter provided an update on the 16 November 2011 (sic 2017) Cabinet meeting. The note continues:

Discussed pros and cons of permanent generator options, decided to exercise purchase option now, and progress consultation and relocation work. Bridging submission (unsolicited proposal) approved. Will be executed shortly.

155. Within these documents is an extract from a document described as “Our Energy Plan” dated 21 November 2017. It is marked “Cabinet in Confidence”. Behind a page marked “Cabinet Update” appears a page entitled “Cabinet Decisions”. Under the heading “Emergency Generators” appear the following bullet points:

• Cabinet Submission presented pros and cons of the alternative timing for the execution of options to buy. • The submission included a recommendation with options. • Cabinet discussed the submission and decided: o To undertake the community awareness process.

58 The attendees were recorded as Mr Sam Crafter, Dr Don Russell (who left after agenda item 2), Mr Tony Circelli (who also left after agenda item 2), Ms Natalie Atkinson, Mr Peter Hawkes, Mr Paul Radford, Ms Julia Grant (proxy), Mr David Reynolds, Mr Michael Wait SC and Mr Richard Day (who was apparently late). Mr Danny Price of Frontier Economics dialled in for agenda item 1. It would seem that agenda item 1 was “Bridging” whereas agenda item 2 was “Generation Update”. This appears to include the “permanent generator” topic. 59 The attendees at this EPIC meeting were Mr Sam Crafter, Dr Don Russell, Mr Tony Circelli, Ms Natalie Atkinson, Mr Peter Hawkes, Mr Paul Radford, Ms Sandy Pitcher and Mr Richard Day. Apologies were received from Mr David Reynolds and Mr Michael Wait SC.

o To execute the option to procure the generators ASAP. o To conclude the relocation option study. o Return to Cabinet for relocation decision after the community awareness process has concluded.

156. The EPIC minutes for Tuesday, 28 November 2017 record a discussion about the generator purchase announcement having been made earlier that morning.60

157. I understand from my discussions with officers from DPC that the Cabinet submission outlined the various financial and other implications associated with exercising the option prior to a Cabinet decision being taken to exercise the option to purchase on 16 November 2017.

158. I am advised also that various financial models were prepared and incorporated in that Cabinet submission. I have not seen that submission or any underlying work prepared in November 2017.

159. On 28 November 2017 the Energy Minister executed the “Assets Sale Contract” with APR Energy Holdings Ltd and his signature was witnessed by Mr Nick Smith, Director of Energy Programs and Services. By this agreement the South Australian Government recorded that it had exercised the option to purchase in accordance with the terms of the Call Option Deed and documented its purchase of the generation assets. The deed contains a copy of the Exercise Notice which was signed by the Energy Minister, and witnessed by the then Premier, on 28 November 2017.

160. According to the then Energy Minister:61

We announced in March after a successful tender process that we would buy these generators. We would lease for the first two years and then purchase them to have them permanent at a permanent site. Now we needed to do propriety works, to make sure we have a site where we can move these generators to... the generators are within the scope of the $550 million... No we got a very good price. ...we bought the generators, we own them. What do we own? We own 276 megawatts of aero-derivative gas-fired turbines. ...we announced in March we were purchasing a state-owned generator.

161. On 28 November 2017 it was announced that the option to purchase had been exercised, the South Australian Government having signed a contract to buy the nine diesel gas generators:62

This is a decision that is in the public interest to give the public control of the state-owned asserts, there is no reason why we shouldn’t proceed with that at all due haste, and that is exactly what we are doing.

60 The attendees of this EPIC meeting were Mr Stuart Hocking (proxy), Mr Michael Wait SC (who left after agenda item 2), Mr Richard Day, Mr Tony Circelli, Mr Paul Radford, Ms Sandy Pitcher, Mr Sam Crafter, Mr Peter Hawkes, Ms Natalie Atkinson, Ms Tahnya Donaghy (proxy, late). Apologies were received from Dr Don Russell and Mr David Reynolds. 61 Radio 5AA 28 November 2017 between 9.19am and 9.29am 62 ABC Radio Adelaide, 28 November 2017 1pm, the Honourable Jay Weatherill MP, Premier.

162. A report by AEMO on 28 November 2017 warned that Victoria and South Australia still had the highest likelihood of more hot days and longer heat waves than “normal”.

163. It was then suggested that there were disparities between estimates provided by the State Government, as distinct from the estimates provided by AEMO, regarding the capacity of the diesel generators; the State Government had suggested 276MW whereas AEMO had suggested 170MW. Part of the explanation may have been that all generation is “de-rated” from name plate capacity to allow for the loss of generating capacity during very hot weather.63

164. Mr Koutsantonis was asked in the House of Assembly later that day whether the full cost of leasing and commissioning the nine diesel generators for one year, then buying them and then relocating them to another site, was in excess of $400 million.

165. That question was not answered.

166. The Minister was later asked what the benefit was in exercising the option early and his answer included the capacity to commence planning for their permanent relocation. The alternative, he said, was spending money and time finding a permanent location when “we haven’t bought them yet”. He was then asked why he said it was necessary to exercise the purchase option so that the Government could start its planning process for a third permanent location when the government had actually started developing a third permanent location, six months previously. The Minister said that this was “all part of our plan”. As part of his answer he spoke of less reliance and more self- sufficiency:

That’s why we are buying our own state-owned generator, and I do not understand why members opposite want to sell it already. Procurement and relocation: The State-owned emergency power plant

167. In the period December 2017 to January 2018 an acquisition plan was developed for what was by then described as a “State-owned emergency power plant”. The first stage of that process was the preparation of an ‘Acquisition Plan’ - “State-Owned Emergency Power Plant” dated 13 December 2017.

168. That estimated the value of the proposed acquisition required for relocation at $80 million, with the estimated value of the proposed acquisitions for operations and maintenance at around $7.5 million per annum (with an estimated total value of $187.5 million over the potential life of the twenty-five-year contract).64

169. That was made the subject by a Minute prepared by the Chair, Accredited Purchasing Unit to the Chief Executive, DPC on 21 December 2017, who endorsed it on 5 January 2018.

63 Adelaide Advertiser, Tuesday, 28 November 2017, page 2. 64 Acquisition Plan “State-Owned Emergency Power Plant” dated 13 December 2017, pages 6, 19.

170. In correspondence from the Acting Chief Executive dated 5 January 2018 to the Presiding Member of the State Procurement Board, it was highlighted that the twenty- five-year contractual term comprised an initial term of ten years with options to extend for further periods of five years each. Insofar as there was an engineering and construction aspect, including temporary site decommissioning, equipment relocation and permanent site construction, the estimated cost was $80 million (GST inclusive) which was said to be considered “works” and not a “procurement operation and does not require State Procurement Board approval” but which would be considered by the Public Works Committee.65

171. The matter was considered by the State Procurement Board at its meeting on 15 January 2018, at which time Mr Sam Crafter and Mr Bryan Scruby attended.

172. At that meeting, the Board was advised that there had been changes to the proposed timeline and the risk management plan had not yet been finalised. The Board’s views were confirmed in a letter dated 19 January 2018. The Board determined that it could not approve the Acquisition Plan given “the information disclosed and the high-risk rating for the procurement and the absence of a risk plan”. The Board suggested that the ‘Acquisition Plan’ be resubmitted. The Board requested that it be addressed on:

172.1. The preference for a single process and single provider, particularly given the plant’s limited usage in an emergency, and the Board would therefore appreciate additional information to support the strategy of linking the engineering procurement and construction with the Operations and Management components.

172.2. In resubmitting an amended timeline for the procurement, the Board requested information in the critical path for each aspect of the project, being both Engineering and Construction, as well as Operations and Management.

172.3. The covering letter to the submission advised that the Engineering and Construction aspect was not considered a procurement operation. The Board wanted to know the basis of that determination and confirm what approval was being sought from the Board.

172.4. The Board asked DPC to clarify the rationale for the 10+5+5+5-year O&M term in the context of the anticipated equipment life.

173. On 31 January 2018 a (revised) “Permanent Emergency Power Plant Acquisition Plan” was prepared, with much the same parameters as previously, namely, an estimated total value of $187.5 million (GST inclusive). It was said in the covering Minute that the Energy Plan forecast included an allowance of $80 million for the relocation capital expenditure plus $7.5 million per annum until 2020-2021 for operations and

65 Correspondence from Dr Tanya Donaghy, Acting Chief Executive DPC dated 5 January 2018 to Ms Nicolle Rantanen, Presiding Member, State Procurement Board.

maintenance. Operations and maintenance funding from 2021-2022 would be considered part of future budget processes.66

174. By letter dated 8 February 2018 Dr Don Russell, Chief Executive DPC again wrote to the Presiding Member of the State Procurement Board. He explained that the ‘Acquisition Plan’ had been revised in light of the requests made, and a schedule was prepared of changes to enable comparison with the previous submission.

175. On 8 February 2018 the Presiding Member of the State Procurement Board wrote to Dr Russell advising that it had approved the Acquisition Plan, noting that it would also be considered by the Public Works Committee of the Parliament. It was noted that there was an absence of final evaluation criteria. Approval was explicitly made subject to the provision of finalised evaluation criteria and weightings to Policy, Standards and Governance in DPC prior to the opening of tenders. Importantly, it was clarified that:

The operation and maintenance contract term is for a period of ten years with the option to extend for a further three five-year terms. The total anticipated value of the construction, and operation and maintenance contract, including extension options, is $267.5million (including GST).

176. The Board approved the nomination of Dr Russell, or his delegate, to approve the purchase recommendation. No further reference to the Board was required in relation to the proposed procurement or purchase recommendation unless there was a “material deviation/variation”.

177. On 19 February 2018 an Evaluation Plan for the supply of the State-Owned Emergency Power Plant was published. The First Term of Reference

178. The key legal agreements to which I have referred clearly and unambiguously disclose an intention to create binding legal relations. The transactions were clearly commercial in nature.67 Each of these documents was entered into between the Minster for Mineral Resources and Energy and APR Energy.

179. The fact of the placement of the Energy Minister’s signature on the Exercise Notice, and then in the execution clause of the Asset Sale Contract, together with his use of the common seal of his Department, is telling.68

180. The Call Option Deed dated 7 August 2017 specified by clause 2.2(c) that the “Exercise Notice and Asset Sale Contract once given is irrevocable and cannot be withdrawn by SAG without the prior written consent” of APR Energy.

66 Minute to Chief Executive from the Chair, APU dated 7 February 2018 endorsed by the Chief Executive, CPD on 8 February 2018. 67 Ermogenous v Greek Orthodox Community of SA Inc (2002) 209 CLR 95 68 Toll (FGCT) Pty Ltd v Alphapharm (2004) 219 CLR 165, [38]-[ 45]

181. It has been said that “it should not be overlooked that on occasion contract may be chosen by Government as the mode of public administration”.69 Ordinarily, when a Minster of the Crown contracts with a person, that minister does so as the agent of the Crown. The other party is taken to have contracted with the Crown.70 Accordingly, Ministers are both delegates and agents of the Crown.71 Though agency is often based on ostensible authority,72 in South Australia the Governor, acting on the advice and consent of Executive Council, has conferred authority on the Premier to enter into any contract or deed on behalf of the Crown, and on any other Minister to do so in respect of any matter within that Minister’s portfolio.73

182. It follows that the Crown through the Executive may enter into contracts without statutory authorisation. This is sometimes said to be in the exercise of “personal powers”, subject only to the constraint that they be exercised in the course of administering a recognised part of the Government of the State. This is said to explain why “the Crown’s power to contract is still likely derived from the personal powers”.74

183. In New South Wales v Bardolph the High Court found that a contract entered into between the proprietor of a newspaper and an agent of the Premier was a contract made by the Crown, and thus binding upon the Crown.75

184. The circumstances in which these contracts were entered into involve none of the complicating features associated with the Gillman land transaction.76

185. In my opinion the State of South Australia is bound to purchase under the terms of the Asset Sale Contract.

186. To be clear, although I do not regard the procurement process as compliant, I do not regard that as affecting the authority of the Minister to bind the State. There is no suggestion that APR Energy had any inkling that these processes had not been followed.

69 Anictomatis v Northern Territory (2008) 23 NTLR 55, [42] per Southwood J 70 By the Constitution Act 1935, ss 65 and 66 Ministers of the Executive are described as “Ministers of the Crown” and by the Crown Proceedings Act 1992, s 4 the term “Crown” includes “a Minister...of the Crown”. 71 Selway “The Constitution of South Australia”, Federation Press, 1997, [6.4.9]. 72 Robertson v The Minister of Pensions [1949] 1 KB 227. 73 South Australian Government Gazette, 24 February 1994, page 525. 74 Selway, [7.2.5] 75 New South Wales v Bardolph (1934) 52 CLR 455, 495 per Rich J, 501-502 per Starke J: “Contracts made on behalf of the Crown by its officers or servants in the established course of their authority and duty are Crown Contracts, and as such bind the Crown”. See also Dixon J at 507. This line of authority was accepted and followed by the Full Court in A v C (2015) 123 SASR 477, [25]-[40] per Kourakis CJ (with whom Kelly and Peek JJ agreed), albeit in connection with contracts entered into by former Premiers Rann and Weatherill. 76 See for example Acquista Investments v The Urban Renewal Authority [2014] SASC 206 per Blue J and Acquista Investments v The Urban Renewal Authority (2015) 123 SASR 147 (Full Court) in which Vanstone and Lovell JJ disagreed with Debelle AJ (see for example [376]-[380] as to whether a contract for the option to purchase Crown land granted by the Urban Renewal Authority was void or invalid notwithstanding Cabinet approval). Special leave to appeal was granted but the matter was settled before the appeal was heard.

187. I next turn to the advantages associated with the early exercise of the option. During my meetings with members of the “Energy Team” I was advised that there was a lengthy time frame required for planning for the relocation of the turbines. I was advised that that was one of the factors in a recommendation to the Cabinet that the option to purchase be exercised in late November 2017.

188. The Permanent Emergency Power Plant “Acquisition Plan” dated 31 January 2018 refers in section 13 (from page 20) to the mix of completed and target dates to allow for completion of relocation before the 2019-2020 summer. The time frames which are identified included a tender process culminating in the award of a contract by 9 May 2018. It was explained that the target contract award date allowed sufficient time for the contractor to review existing sites for relocatable components, design the relocation of infrastructure, procure specialist gas conversion infrastructure (likely from overseas) and prepare the site ahead of the target date for the first group of turbines to be installed at Bolivar by July 2019. A second group was to then be installed by October 2019, with construction works completing and the operation and maintenance period due to commence on 1 November 2019.

189. The ‘Acquisition Plan’ also explained that if the contract award date was delayed there was a risk that the relocation would be delayed until April 2020 (page 21).

190. However, the period between May 2018 and July 2019 is a long period, not otherwise explained. No doubt there was a strong preference to avoid relocation during summer months and, to a lesser extent, during winter months.

191. Given the desire to start the procurement process before the caretaker period began on 17 February 2018 (page 21) it is difficult to see why opportunities for extending the lease arrangements were not at least considered. In any event, by the time of the ‘Acquisition Plan’ dated 31 January 2018 it is difficult to see how the delay between then and March would prove critical. Granted, what was then being proposed had been effectively set by the decision to exercise the option and purchase in late November 2017.

192. Apart from assisting the logistics associated with relocation there does not appear to have been any particular benefit identified in connection with the early exercise of the option. I acknowledge that it was recognised that the need for back-up power was “urgent”.

193. However by late November 2017 that objective had been, commendably, well secured.

194. It may be accepted that lease costs in the order of $50 million would be avoided by the early exercise of the option ahead of the second lease period.77 But the opportunity was lost to take the time to reflect on whether the large purchase, relocation and operation

77 Treasury Minute dated 26 March 2018, page 3, concerning the December 2018 – November 2019 period.

and maintenance costs could be avoided, together with reflection on the period of time for which this additional capacity may actually be required.78

195. One of the factors in assessing logistics is undoubtably the limited tenure of the sites on which the turbines are presently located. For example, the SA Water facility at Lonsdale is subject to a 3-year term that is supplemented by a 3 year right of renewal. By contrast, the GMH facility at Elizabeth is also subject to a 3-year term but there is no right of renewal.

196. I have not seen evidence that the opportunities for extending tenure at the sites were explored, nor does any consideration appear to have then been given to the capacity for “more electricity supply options” to become available in “the South Australian region of the NEM” as a result of which “not all 9 units may be required for emergency generation”.79

197. Indeed, the capacity to retain the 4 turbines at Lonsdale for future summers, providing up to 123MW of emergency power (fuelled by diesel) whilst disposing of the 5 units at Elizabeth, does not appear to have been considered as a possibility until mid March 2018.80

198. In short, apart from the logistical issues to which I have referred, there does not appear to have been any overall advantage associated with the early exercise of the option to purchase. As mentioned earlier, whether a ‘saving’ in lease costs represented an overall saving turns on the existence of a demonstrable need for a permanent plant. The Second Term of Reference

199. I have already set out in some detail the applicable legislation, guidelines and policies.

200. It is clear that on 13 April 2017 the State Procurement Board approved the acquisition plan from DPC for the provision of 200MW short-term electricity generation. The total anticipated value of the contract was $112 million (including GST). That approval carried with it no approval for the purchase of the turbines. It was limited to a lease arrangement.

201. What was put forward at the end of June 2017 was approval for the ‘Detailed Purchase Recommendation’ for short-term electricity generation, which was materially different to what was placed before the Board in April 2017.

202. As I have pointed out, by late June 2017 the estimated total cost of the proposed contracts for the maximum term had risen to $177 million, the estimated value of the option to purchase being $227 million, with an estimated total value of $404 million.

78 Treasury Minute dated 26 March 2018, page 3, concerning the December 2018 – November 2019 period. 79 Minute from the Energy Plan Implementation Task Force, DPC to the Minister for Energy and Mining dated 19 March 2018. 80 Minute from the Energy Plan Implementation Task Force, DPC to the Minister for Energy and Mining dated 19 March 2018, apart from the fleeting reference given to the topic in Aurecon’s 18 October 2017 report.

In the event of the exercise of the option to purchase “a further Cabinet submission” was required for “expenditure approval”.

203. The Minute from the Acting Chair of the Accredited Purchasing Unit to the Chief Executive of DPC dated 29 June 2017 cited a delegation by the Board to the Chief Executive of “the authority to approve the purchase recommendation”.

204. However, that approval was confined to the “proposed procurement or purchase recommendation unless there is a material deviation/variation”.81 There was plainly a “material deviation/variation” when the contract value was markedly increased and was altered to include an option to purchase. No authority granted to the Chief Executive in April 2017 envisaged those changes.

205. In my opinion, the State Procurement Board did not delegate to Dr Russell the authority to approve the purchase recommendation with an estimated value of $177 million, still less with authority to approve a total value of $404 million, despite the suggestion to the contrary in the Minute dated 29 June 2017. I acknowledge that at least some of this was put before Cabinet on 21 June 2017.

206. However there is also the fact that the purchase price of $227 million, whilst appreciably lower than the costs suggested in connection with the permanent State- owned gas-fired plant (as revealed by PwC’s work), had never really been ‘market tested’, as the procurement guidelines required. I do not think that a comparison of different projects with different specifications and requirements in separate tender processes can be so easily compared. One might test the proposition by notionally asking an unsuccessful tenderer in the permanent plant process about the fairness, if not also the reliability, of comparing its tender response against a proposal made in connection with another project under different specifications and tender conditions.

207. Because there was a “material deviation/variation” the matter should have been put back before the State Procurement Board for its approval in the period June to July 2017, before decisions were taken to proceed.

208. Instead, the Chief Executive approved the purchase recommendation on 29 June 2017 and, on the same day, the Manager, Procurement, sent a minute to the Executive Director, Energy Plan Implementation Task Force advising him of the approval of the purchase recommendation.82

209. This issue was not brought back to the State Procurement Board until it was informally discussed on 9 October 2017.

81 Correspondence from the State Procurement Board to the Chief Executive Officer DPC dated 13 April 2017. 82 Minute from the Manager, Procurement, to the Executive Director, Energy Plan Implementation Task Force “Purchase Recommendation: Office of the Chief Procurement Officer – Short-term Electricity Generation” dated 29 June 2017, confirming an estimated “total value of the proposed contract plus the purchase option” of $404,460,456.00 (GST inclusive).

210. I have been given the PowerPoint presentation which was prepared but not used. It is reasonable to assume that at least some aspects of that presentation featured in the informal discussion with the Board on 9 October 2017. Even then, the PowerPoint identified the cost break down for “temporary generation” at $111.5 million, with procurement estimated at $227 million and a corresponding estimate of “permanent generation facility – capital” of $300 million of the $550 million Energy Plan Budget. It was explained that “preliminary work indicates purchase and relocation within the original budget”.

211. The PowerPoint presentation also explained that there were issues the subject of advice from Crown Law but that the State’s contractual arrangements for each procurement component were said to comprise, largely, “goods and services” although relocation might involve “some construction”. The State Procurement Board was assured that the Board’s letter dated 8 March 2017 had only been used “for the procurements included in the Energy Plan and outlined in this presentation”.

212. Some of these matters were confirmed in the document prepared and sent to the Board following the discussion on 9 October 2017 - but the issue to which I have referred regarding the difference between the terms of the delegation granted in April 2017, as against what was approved in late June 2017, was not recognised or explained. Rather, insofar as it was acknowledged that some Energy Plan procurements had not been presented to the State Procurement Board for approval it was (relevantly) explained that: The procurement was for the engineering and construction of a government owned asset (emergency power plant-permanent) and was approved at the Public Works Committee of Parliament.

213. Respectfully, that confused two distinct and separate processes. True, the Public Works Committee considered and approved the “project” insofar as it involved construction. What was actually put before the Public Works Committee was the subject of very significant revision: the permanent option which did involve construction had been ‘shelved’ only a few days before the hearing commenced. By the time of the Final Report the procurement clearly and primarily concerned the acquisition of goods and services, and that was required to be approved by the State Procurement Board.

214. I do not think that the failure to obtain State Procurement Board Approval was remedied by the informal discussion in October 2017 or by what was later described as the “State Owned Emergency Power Plant” commencing in December 2017.

215. As the ‘Acquisition Plan’ dated 13 December 2017 made clear (page 7) what was covered was “the procurement process to relocate the GE TM2500 units to a permanent location and to secure the operation and maintenance of the facility”. The estimated value of the procurement was $80 million together with $7.5 million per annum for operation and maintenance. Clearly, in the covering letter from Dr Tahnya Donaghy, Acting Chief Executive DPC, dated 5 January 2018 the potential acquisition cost of $187.5 million over a potential 25-year period made no allowance for the cost of purchasing the turbines. That did not change when the Board finally gave its approval by letter dated 8 February 2018 to Dr Russell. Indeed, the only relevant change following the provision of further information was that the total anticipated value of the

construction, operation and maintenance contract, including extension options, was said by the Board to approximate $267.5 million.

216. In these circumstances it is my opinion that the applicable procurement policies and guidelines were not followed in connection with the obtaining or the exercise of the purchase option. The Third Term of Reference

217. At the outset of this report I have already referred to the varying estimates of the costs associated with the exercise of the purchase option, combined with the cost of relocating, operating and maintaining the turbines.

218. The likely financial exposure over the full potential 25-year period exceeds the range $411.5 million to $427 million (which range includes relocation construction costs). This range does not incorporate all elements of the total anticipated cost of operation and maintenance contracts, including extension options, which approximates $187.5 million.83

219. As I have earlier explained, the total expenditure will therefore be at least $609.5 million, which incorporates the temporary lease arrangements.84 The Fourth Term of Reference

220. As I have endeavoured to explain, in my opinion the State Government must proceed on the basis that the State is bound by the Asset Sale Contract dated 28 November 2017.

221. In my opinion decision-making concerning the future management and ownership of the turbines will be guided by reliable advice. The Government should seek up-to-date independent expert advice on the need for an emergency electricity generation facility beyond the short-term. Unless it is persuasively demonstrated that an emergency electricity generation facility is required on a medium to long term basis, there seems to me inadequate justification for incurring the relocation, operation and maintenance costs in the range $187.5 million to $267.5 million.

222. The exercise by the former Government of the Call Option Deed option exercise notice, culminating in the entry into the Asset Sale Contract on 28 November 2017, was predicated on concerns about logistical arrangements “driven by the long lead supply of high voltage transformers which can be in excess of 15 to 18 months”.85

83 State Procurement Board letter to the Chief Executive DPC dated 8 February 2018 84 ‘Detailed Purchase Recommendation’ - “Short-Term Electricity Generation” dated 27 June 2017, page 10. That is, $227 million plus $267.5 million ($494.5 million) in addition to initial lease and associated costs of $115 million. 85 Minute from the Executive Director, Energy Plan Implementation Task Force DPC to the Minister for Energy and Mining dated 19 March 2018.

223. The existing arrangement assumes termination of the lease on completion of the initial 13-month period on 13 November 2018, followed by acquisition of the turbines. This assumes written notice to SA Power Networks 65 days ahead of termination, which then triggers the purchase arrangements unless alternative arrangements can be negotiated and agreed.

224. In my view, discussions with APR Energy must quickly be undertaken to determine the appetite for renegotiating the lease arrangements (presumably by way of extension) as well as toward releasing the State from its purchase obligations.

225. The resale value of the units is unpredictable because it will depend, at least in part, on the electricity generation market at the time of proposed sale, and whether the units can or should sold as part of an established plant, or as an entire group, or in smaller groups of individual units. External engineering and national electricity market analysis and advice is required.86

226. The initial advice apparently recently received by the Energy Team suggests that the easier resale option is a sale back to APR which could conceivably reposition the units for other markets and other projects.87

227. In all probability, any resale price will not reach $227 million.

228. Other potential options include a sale of the units to the private sector, whether at the temporary or relocated permanent sites. Apparently, the South Australian Government has already received offers from a private sector entity to “own and operate the emergency power plant” whereby the owner would have the right to operate the facility for commercial gain but be obliged to make it available to the Government in the event emergency generation was required. Nonetheless both the relevant Minister and AEMO have the power to compel any generators in the NEM to operate in emergency situations, regardless.88 Conclusion

229. The scale and volume of activity required to implement the former Government’s Energy Plan ought not be underestimated. A vast amount of work and coordination was required to analyse and implement various of the objectives then identified and announced.

230. I have been required to consider only two aspects of a very broad plan involving very significant and complex policy, legal, financial and engineering issues.

231. Nonetheless, the evidence in favour of the case for a permanent, emergency electrical generation facility is sparse indeed. None of the procurement materials or expert reports made available to me cite expert advice on the need for a permanent plant.

86 Minute from the Executive Director, Energy Plan Implementation Task Force DPC to the Minister for Energy and Mining dated 19 March 2018. 87 Treasury Minute dated 26 March 2018. 88 Treasury Minute dated 26 March 2018.

232. A recent review of the National Electricity Market apparently shows that load-shedding events have occurred infrequently and, typically, last less than 1 hour. The generators the subject of this report were therefore forecast to operate only a few times each year, and then for short periods.89

233. It was said in March earlier this year that initial assessments of South Australian electricity supply and demand indicated that the emergency generators would be run up to 2 hours each month in the summer peak period, and up to 1 hour each month at other times of the year. However, the precise number of generators to be operated would depend upon the forecast shortfall, as well as on prevailing fuel costs.90

234. During the 2017-2018 summer period AEMO requested that the units be placed on informal standby for operation on three occasions, but they were ultimately not required.91 In my view careful analysis and planning is required before committing the State to retaining and operating nine turbines which, conceivably, may not all now be needed.

M.C. Livesey QC Special Investigator 30 August 2018

89 Minute from the Executive Director, Energy Plan Implementation Task Force DPC to the Minister for Energy and Mining dated 19 March 2018. 90 Minute from the Executive Director, Energy Plan Implementation Task Force DPC to the Minister for Energy and Mining dated 19 March 2018. 91 Minute from the Executive Director, Energy Plan Implementation Task Force DPC to the Minister for Energy and Mining dated 19 March 2018.

Attachment 1 – Initial Request for Documents

After receiving and considering the key contracts (referred to in paragraph 1 below) on 4 April 2018, I spoke with Special Counsel to the Chief Executive of the Attorney-General’s Department, Ms Lucinda Byers. She confirmed my request for documents on 6 April 2018 as follows:

1. The full suite of contractual documents, beyond those you have been provided already – namely all documents which are referred to in: a. the Short-term Capacity Contract dated 6 July 2017 b. the Call Option Deed dated 7 August 2017 c. the Asset Sale Documents dated 28 November 2017 (those being the documents you have already received);

2. Any financial or commercial modelling or advice that has already been undertaken to assess and compare the implications of the different options contemplated within the documents you have already received;

3. To the extent that there are no existing documents within the scope of (2) above, assistance from an appropriate Department of Treasury and Finance employee (or other appropriate person) to provide that financial or commercial modelling or advice;

4. All documents comprising the applicable procurement policy regime to the relevant transactions;

5. All documents recording compliance or otherwise with the applicable procurement policy regime;

6. All legal advice received in relation to the relevant transactions;

7. All email correspondence sent and received in relation to the relevant transactions;

8. Assistance and advice in respect of any Cabinet documents concerning the relevant transactions.

Attachment 2 – Responses to Request for Documents, Further Requests

1. On 5 April 2018 I met with the Attorney-General and was given the key contracts and documents concerning the Public Works hearing in August 2017.

2. On 6 April 2018 I was given a suite of News Releases by Ministers in the former Government which explained the “Energy Plan”.

3. At 5.15pm on Friday 4 May 2018 I received a box containing the first of a number of folders containing documents in response to my initial request. Further documents were received over time. The documents were supplied by officers from the Department of the Premier and cabinet and by officers in the “Energy Implementation” team within the Department for Energy and Mining. Attached is a listing of the approximately 130 documents received from that team.

4. I met with members of that team on 11 May, 18 May and 8 June 2018.

5. On 23 May 2018 I wrote to the Acting Chief Executive, Department of the Premier and Cabinet, requesting the “submissions …made to Cabinet in July and November 2017, and on which Cabinet made decisions relevant to the procurement on 27 July and 16 November 2017. The first involved the decision to enter into lease arrangements with an option to purchase, and the second involved the decision to exercise the option”. I explained that these appeared very relevant to my investigation and that I was required to report by 30 June 2018.

6. I followed up that request on 7 and 12 June 2018. I was told that advice was being sought from Crown Law officers. On 29 June 2018 at 5.18pm I was advised “Based on long standing Constitutional and Cabinet conventions, the Premier has determined that he should not release the Cabinet documents of a former government without their approval, and as such will write to the Leader of the Opposition seeking his agreement to release these documents to you”. Obviously no response was received by 30 June 2018. Ultimately agreement to release was not given.

7. Following my request to members of the Energy Team at the meeting on 18 May, on 25 May 2018 I was given a folder which I was told contained relevant documents concerning approaches made to the State Procurement Board. During my meeting with Mr Sam Crafter and Mr Bryan Scruby on 8 June 2018 I pointed out that there did not appear to be any submission or presentation to the State Procurement Board seeking approval for the entry into or exercise of the option in November 2017. Mr Crafter said that he would make further inquiries.

8. In response, on 14 June 2018 I received documents concerning “updates” provided on 9 October 2017 by the Energy Plan Implementation Program Director to a State Procurement Board meeting regarding the status of the Plan’s implementation. I was told a PowerPoint presentation was prepared, but not ultimately used, as the Board used the time to discuss matters informally. I was given the PowerPoint presentation dated 9 October 2017 prepared for the State Procurement Board meeting (but not presented), a

word document dated 9 October summarising the key points discussed at the State Procurement Board meeting, which was provided to the Board after the meeting, and a letter from the then Acting Chief Executive DPC to the State Procurement Board dated 3 January 2018, providing a further “update”.

9. On 13 June I was given details of Treasury officers who may be able to assist my investigation. I contacted Treasury on 25 June and spoke with Mr Kevin Cantley on 2 occasions on 27 June 2018.

10. I received a Treasury minute and associated documents and financial projections from Mr Cantley on 28 June 2018.

Document Name Description Date document Provided to Date executed/approved Special Provided etc. Investigator 48

Environment Deed Poll (SAG_APR) Indemnity provided 20-July-2017 (executed by SAG 20 July 2017) by SAG to APR for any liability for Y 4/05/2018 contanimation on the sites not caused by APR. Environment Deed Poll (SAG_SAPN) Indemnity provided 31-July-2017 (executed by SAG 31 July 2017) by SAG to SAPN for any liability for Y 4/05/2018 contanimation on the sites not caused by SAPN. SAG.APR Deed - Executed 24.7.17 This is the Deed 24-July-2017 referred to in the amending agreement to the Y 4/05/2018 STCC between SAG and SAPN dated 31 July 2017. Call Option Deed - Generation Assets signed Call Option Deed - 07-August-2017 APR Energy Holdings Ltd Generation Assets entered into between SAG and APR (signed by APR) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed) Call Option Deed - Generation Assets signed Call Option Deed - 07-August-2017 Min for Mineral Resources & Energy Generation Assets 07_08_17 entered into between SAG and APR (signed by SAG) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed) Option Security Deed signed counterpart Min Schedule 6 of the 07-August-2017 for Mineral Resources & Energy Call Option Deed - Generation Assets Y 4/05/2018 (signed By SAG)

Option Security Deed signed counterpart of Schedule 6 of the 07-August-2017 APR Energy Holdings Ltd Call Option Deed - Y 4/05/2018 Generation Assets (signed by APR)

Priority Deed signed counterpart APR Energy Schedule 7 of the 07-August-2017 & Power Rental Op Co Aus x 2 Call Option Deed - Generation Assets (full Deed signed by APR and Power Rental Op Co) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed) Priority Deed signed counterpart of Bank of Schedule 7 of the 07-August-2017 America x 1 Call Option Deed - Generation Assets (countersigned by Bank of America) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed) Priority Deed signed counterpart of SA Power Schedule 7 of the 07-August-2017 Networks Call Option Deed - Generation Assets (countersigned by SAPN) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed) Priority Deed signed counterpart of Min for Schedule 7 of the 07-August-2017 Mineral Resources & Energy Call Option Deed - Generation Assets (countersigned by SAG) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed) Transformer Deed signed counterpart of APR Schedule 4 of the 07-August-2017 Energy Holdings Ltd Call Option Deed - Generation Assets (full Deed signed by APR) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed)

Transformer Deed signed counterpart Min for Schedule 4 of the 07-August-2017 Mineral Resources & Energy dated 07_08_17 Call Option Deed - Generation Assets (countersigned by SAG) Y 4/05/2018 (Deed not dated - assumed that signed the same date as the Option Security Deed) Call Option Term Sheet 20170706 Agreement 06-July-2017 between SAG, APR and Power Rental Op Co Australia LLC Y 4/05/2018 regarding various options available relating to the generators Asset Sale Contract – Generation Assets Contract between ################ SAG and APR regarding the Y 4/05/2018 purchase of the generators Call Option Deed – Generation Assets – Approval to ################ Exercise Notice exercise the relevant Option Y 4/05/2018 under the Call Option Deed SAPN Short-term Capacity Contract – FINAL Contract executed 06-July-2017 – (SAPN & SAG) 6 July 2017 between SAPN and SAG for Short- term Electricity Y 4/05/2018 Generation (Temporary Generators) SAPN Short-term Capacity Supply Contract - Contract executed 06-July-2017 FINAL - (SAPN & APR) 6 July 2017 between SAPN and APR for Short-term Electricity Y 4/05/2018 Generation (Temporary Generators) Amendment to STCSC - Condition Precedent APR and SAPN 20-July-2017 Date (APR-SAPN) 200717 acceptance of changes to the Y 4/05/2018 Condition Precedent Date SAPN Negotiated Connection Offer (executed Negotiated 31-July-2017 by SAG 31 July 2017) Connection Offer between SAG and Y 4/05/2018 SAPN executed by SAPN and SAG

Nondisclosure of STCC letter 050817 Letter from SAPN 11-August-2017 regarding nondisclosure of the Short-term Y 4/05/2018 Capacity Contract between SAG and SAPN Relocation Report Master_Draft_Clean Study prepared for 18-October-2017 the relocation of the Temporary Y 4/05/2018 Generators by an external party 200 MW Financial Evaluation Model v2.2 Financial 15-June-2017 evaluation model developed by SAPN to assess the Y - Soft 4/05/2018 responses received copy relating to the procurement process. 1. Procurement-Matrix Procurement N/a matrix summarising key procurement Y 4/05/2018 documentation and process required for different dollar thresholds 2. DPC-Procurement-Governance-Policy Policy document N/a which defines the governance Y 4/05/2018 framework for the procurement operations of DPC. 3. Procurement-Process-Approvals-Guideline Guideline which N/a defines the requirements within the DPC procurement governance Y 4/05/2018 framework for obtaining formal approval of procurement proposals and processes. 4. Contract-Management-Guideline Guideline which N/a details the requirements within the DPC procurement Y 4/05/2018 governance framework for the management of contracts.

5. Contract-Register-and-Disclosure-Guideline Guideline which N/a details the requirements within the DPC procurement Y 4/05/2018 framework for the register and disclosure of contracts. 6. Market-Process-and-Supplier- Guideline N/a Communication-Guideline developed to assist staff in managing communication with potential Y 4/05/2018 respondents at all stages of the procurement process. 7. Tender-Receipt-Registration-Guideline Guideline which N/a details the requirements within the DPC procurement Y 4/05/2018 governance framework for the receipt and registration of tenders. Letter (SPB to CE) – South Australian Letter from 08-March-2017 Electricity Supply (Final Signed) Presiding Member State Procurement Board (SPB) Y 4/05/2018 regarding procurement process Minute to CE – Engagement of SAPN – Minute to CE 28-March-2017 28032017 regarding Engagement of SAPN and seeking the CE to sign the Y 4/05/2018 letter to the General Manager Corporate Strategy, SAPN Letter to SAPN – Engagement of SAPN Letter to General 28-March-2017 28032017 Manager Corporate Strategy regarding Y 4/05/2018 Engagement of SAPN signed by the CE Acquisition Plan – SPB submission for Submission to SPB 12-April-2017 approval (Final Signed) regarding the Detailed Acquisition Plan Y 4/05/2018 for Short-term Electricity Generation procurement

Acquisition Plan – SPB approved submission SPB approval of 13-April-2017 (Final Signed) the Detailed Acquisition Plan Y 4/05/2018 for the Short-term Electricity Generation SAG Temp Generation Concept Approval Joint Steering 16-June-2017 Report final 160617 Committee endorsement of Y 4/05/2018 options to deliver the Temporary Generation. Minute to CE – Service Agreement – SAG & Minute to CE 23-June-2017 SAPN regarding Service Agreement Y 4/05/2018 between SAG and SAPN SAPN Agreement – Short-term Generation Copy of the 23-June-2017 Supply – signed both parties (June 2017) Service Agreement between SAG and SAPN signed by both parties (Agreement is not Y 4/05/2018 dated - assumed that signed the same date as the accompanying Minute) SAPN Agreement – Short-term Generation Copy of the 23-June-2017 Supply w Term Sheet & Design Brief (June Service Agreement 2017) between SAG and SAPN with the Term Sheet and Design Brief attached Y 4/05/2018 (Agreement is not dated - assumed that signed the same date as the accompanying Minute) Steering Committee - Decision Minutes Consolidated list of N/a Decision Minutes Y 4/05/2018 from the Steering Committee Steering Committee - Decisions Register Summary list of N/a Summary Decisions made by Y 4/05/2018 the Steering Committee Summary list of N/a Appendices relating to Y 4/05/2018 Decisions made by Steering Committee - Decision Appendices the Steering Summary Committee

Steering Committee - Appendices Appendices N/a relating to Decisions made by the Steering Committee.

Documents provided in other folders: - 6. & 7. SAPN Services Agreement-Short- Term Generation Supply w Design Brief (doc ref. 5.1.12) - 10. Final Concept Report (doc ref. 5.1.9) - 14.a. SAPN Short-term Capacity Supply Contract - FINAL - (SAPN & APR) 6 Y 4/05/2018 July 2017 (doc ref. 1.18) - 14.b. SAPN Short-term Capacity Contract - FINAL - (SAPN & SAG) 6 July 2017 (doc ref. 1.17) - 15. STCC and STCSC Contract CP extension agreement (doc ref. 1.19) - 17. Accepted Network Connection Quote (doc ref. 1.20) - 25.1 Environment Deed Poll (doc ref. 1.2) - 25.2 Priority Deed (doc ref. 1.8- 11) DPC Submission DPC's submission 02-August-2017 to the PWC relating to the installation of the Y 4/05/2018 hybrid turbines as a long-term backup power plant. DPC submission attachment Attachment to 02-August-2017 DPC's submission Y 4/05/2018

PWC presentation Presentation 02-August-2017 prepared by DPC Y 4/05/2018 to accompany the submission PWC presentation - site details Presentation 02-August-2017 prepared by DPC to accompany the Y 4/05/2018 submission relating to the two sites selected Hansard from hearing Hansard record of 10-August-2017 the PWC hearing. Y 4/05/2018

PWC final report Final report issued 15-August-2017 by PWC relating to the installation of the hybrid turbines Y 4/05/2018 as a long-term backup power plant. QON from hearing Questions on notice 13-October-2017 and corresponding Y 4/05/2018 responses provided by DPC Minute (Acquisition Plan - Chair APU to CE) Minute to CE 07-April-2017 – Short-term Electricity Generation (Signed) requesting approval of the Detailed Acquisition Plan for Short-term Y 4/05/2018 Electricity Generation (Temporary Generators) Acquisition Plan - Short-term Electricity Detailed 07-April-2017 Generation (Final Signed) Acquisition Plan for the Short-term Electricity Generation Y 4/05/2018 (Temporary Generators) procurement approved by relevant delegates Letter (Acquisition Plan – CE to SPB) – Short- Letter to SPB from 07-April-2017 term Electricity Generation (Signed) CE requesting approval of the Detailed Acquisition Plan Y 4/05/2018 for Short-term Electricity Generation (Temporary Generators)

Minute (Purchase Rec. – Chair APU to CE) – Minute to CE 29-June-2017 Short-term Electricity Generation (Signed) seeking approval of the Detailed Purchase Recommendation Y 4/05/2018 for the Short-term Electricity Generation (Temporary Generators) Purchase Recommendation – Short-term Approved Detailed 29-June-2017 Electricity Generation (Final Signed) Purchase Recommendation for the Short-term Y 4/05/2018 Electricity Generation (Temporary Generators) Minute (Purchase Rec. – Proc. to ED EPIT) – Minute to 29-June-2017 Short-term Electricity Generation (Signed) Executive Director Energy Plan Implementation Taskforce regarding the Detailed Purchase Y 4/05/2018 Recommendation for Short-term Electricity Generation (Temporary Generators) Letter (SPB to CE) – South Australian Letter from 08-March-2017 Electricity Supply (Final Signed) Presiding Member State Procurement Board (SPB) Y 7/05/2018 regarding procurement process EOI Tender Documents: EOI Tender 28-March-2017 1. EOI Part A – Supply of Gas-fired Documents issued Electricity Generation Plant v1.F to the market 2. EOI Part B – Supply of Gas-fired Electricity Generation Plant v1.F 3. EOI Part C – Supply of Gas-fired Electricity Generation Plant v1.F Y 7/05/2018

Minute (Acquisition Plan – Chair APU to CE) Minute to CE 10-April-2017 – Long Term Electricity Generation (Signed) requesting approval of the Acquisition Y 7/05/2018 Plan for Long Term Electricity Generation

Acquisition Plan – Long Term Electricity Acquisition Plan 10-April-2017 Generation (Final Signed) for Long Term Electricity Generation Y 7/05/2018 procurement approved by relevant delegates Letter (Acquisition Plan – CE to SPB) – Long Letter to SPB from 10-April-2017 Term Electricity Generation (Signed) CE requesting approval of the Acquisition Plan Y 7/05/2018 for Long Term Electricity Generation Evaluation Plan - Long Term Electricity Evaluation Plan 10-April-2017 Generation (EOI) (Final Signed) developed for Long Term Electricity Y 7/05/2018 Generation (EOI phase) Acquisition Plan – SPB submission for noting Submission to SPB 12-April-2017 (Final Signed) regarding Acquisition Plan Y 7/05/2018 for Long Term Electricity Generation Acquisition Plan – SPB noted submission SPB noting of the 13-April-2017 (Final Signed) Acquisition Plan for Long Term Y 7/05/2018 Electricity Generation Evaluation Plan approved amendments Approved 13-April-2017 amendments to the Evaluation Plan developed for Long Y 7/05/2018 Term Electricity Generation (EOI phase) Evaluation Report (Member Endorsement) – Endorsement for 08-May-2017 Long Term Electricity Generation (EOI) Evaluation Report developed for Long Y 7/05/2018 Term Electricity Generation (EOI phase) Minute (Evaluation Report – Procurement Minute to APU 11-May-2017 Services to Chair APU) – Long Term regarding Electricity Generation (EOI) (Signed) Evaluation Report for Long Term Y 7/05/2018 Electricity Generation Evaluation Report – Long Term Electricity Evaluation Report 11-May-2017 Generation (EOI) (Final Signed) developed for Long Term Electricity Y 7/05/2018 Generation (EOI phase)

ITS Tender Documents: ITS Tender 17-May-2017 1. ITS Part A – Supply of Gas-fired Electricity Documents issued Generation Plant v1.F to the market 2. ITS Part B – Supply of Gas-fired Electricity Generation Plant v1.F 3. ITS Part C – Supply of Gas-fired Electricity Generation Plant v1.F 4. ITS Part D – Supply of Gas-fired Electricity Generation Plant v1.F 5. ITS Part D Response Schedule 7 – Pricing Template Y 7/05/2018

Probity Plan and Communications Protocols Probity Plan and 24-May-2017 FINAL (signed) Communications Protocols developed for the Y 7/05/2018 Energy Plan Implementation Taskforce Evaluation Plan (Member Endorsement) – Endorsement for 13-June-2017 Long Term Electricity Generation (ITS) Evaluation Plan developed for Long Y 7/05/2018 Term Electricity Generation (ITS phase) Minute (Evaluation Plan – Procurement Minute to APU 14-June-2017 Services to Chair APU) – Long Term regarding Electricity Generation (ITS) (Signed) Evaluation Plan for Long Term Y 7/05/2018 Electricity Generation Evaluation Plan – Long Term Electricity Evaluation Plan 14-June-2017 Generation (ITS) (Final Signed) developed for Long Term Electricity Y 7/05/2018 Generation (ITS phase) Preliminary Evaluation Report (ITS) (final) Preliminary 23-June-2017 Evaluation Report developed for Long Y 7/05/2018 Term Electricity Generation (ITS phase) DPC SA Energy Plan Procurement Review Report containing 31-July-2017 20170731 the results of the independent Y 7/05/2018 compliance review undertaken by BDO

Minute (Purchase Recommendation – ED Purchase 19-October-2017 EPIT to Chair APU) – Long Term Electricity Recommendation Generation (Final Signed) developed for Long Term Electricity Generation (ITS Y 7/05/2018 phase) to inform APU that State decided to discontinue the tender process JWS Memo - Execution Version of the STCC Memo which 06-July-2017 20170706 provides a summary of the outcomes of the negotiations for the Short-term Y 7/05/2018 Capacity Supply Contract (STCSC) and the Short-term Capacity Contract (STCC). 2. CSO sign-off for Deeds 20170720 Correspondence 20-July-2017 from the CSO regarding Y 7/05/2018 Environmental Deeds Poll and SAG/APR Deed JWS Memo to CSO - Amending Agreements Memo which 28-July-2017 to (STCC) and the (STCSC) 28.07.2017 provides a summary of the Y 7/05/2018 negotiations for the Amending Agreements. JWS Memo to CSO - Amending Agreements Memo which 29-July-2017 to (STCC) and the (STCSC) 29.07.2017 (1) provides a summary of the Y 7/05/2018 negotiations for the Amending Agreements. JWS Memo to CSO - Amending Agreements Memo which 29-July-2017 to (STCC) and the (STCSC) 29.07.2017 (2) provides a summary of the Y 7/05/2018 negotiations for the Amending Agreements. JWS Memo - Execution Version of Amending Memo which 31-July-2017 Agreement to the STCC 20170731 provides a summary of the outcomes of the Y 7/05/2018 negotiations for the Amending Agreements.

JWS Memo - Execution Versions of Option Memo which 07-August-2017 Documents 20170807 provides a summary of the Option Documents including: - Call Option Deed (including form of Y 7/05/2018 Asset Sale Contract); - Transformer Deed; - Option Security Deed; and - Priority Deed. Correspondence 11-August-2017 from Finlaysons Lawyers to JWS Y 7/05/2018 regarding legal 8. Ltr Finlaysons_2 legal opinions re Power opinions in relation Rental Op dated 11_08_17 to APR Correspondence 30-August-2017 from Finlaysons Lawyers to JWS regarding legal Y 7/05/2018 opinions in relation to arrangements between SAG and 9. Ltr Finlaysons_2 opinions dated 30_08_17 APR Statutory 30-August-2017 declaration signed Y 7/05/2018 10. Statutory Dec of APR Energy Holdings by two Directors of Limited 30_08_17 APR Minute (Acquisition Plan – Chair APU to CE) Minute to CE 10-April-2017 – Long Term Electricity Generation (Signed) requesting approval of the Acquisition Y 7/05/2018 Plan for Long Term Electricity Generation Acquisition Plan – Long Term Electricity Acquisition Plan 10-April-2017 Generation (Final Signed) for Long Term Electricity Generation Y 7/05/2018 procurement approved by relevant delegates Letter (Acquisition Plan – CE to SPB) – Long Letter to SPB from 10-April-2017 Term Electricity Generation (Signed) CE requesting approval of the Acquisition Plan Y 7/05/2018 for Long Term Electricity Generation Evaluation Plan - Long Term Electricity Evaluation Plan 10-April-2017 Generation (EOI) (Final Signed) developed for Long Term Electricity Y 7/05/2018 Generation (EOI phase)

Evaluation Plan approved amendments Approved 13-April-2017 amendments to the Evaluation Plan developed for Long Y 7/05/2018 Term Electricity Generation (EOI phase) Evaluation Report (Member Endorsement) – Endorsement for 08-May-2017 Long Term Electricity Generation (EOI) Evaluation Report developed for Long Y 7/05/2018 Term Electricity Generation (EOI phase) Minute (Evaluation Report – Procurement Minute to APU 11-May-2017 Services to Chair APU) – Long Term regarding Electricity Generation (EOI) (Signed) Evaluation Report for Long Term Y 7/05/2018 Electricity Generation Evaluation Report – Long Term Electricity Evaluation Report 11-May-2017 Generation (EOI) (Final Signed) developed for Long Term Electricity Y 7/05/2018 Generation (EOI phase) Evaluation Plan (Member Endorsement) – Endorsement for 13-June-2017 Long Term Electricity Generation (ITS) Evaluation Plan developed for Long Y 7/05/2018 Term Electricity Generation (ITS phase) Minute (Evaluation Plan – Procurement Minute to APU 14-June-2017 Services to Chair APU) – Long Term regarding Electricity Generation (ITS) (Signed) Evaluation Plan for Long Term Y 7/05/2018 Electricity Generation Evaluation Plan – Long Term Electricity Evaluation Plan 14-June-2017 Generation (ITS) (Final Signed) developed for Long Term Electricity Y 7/05/2018 Generation (ITS phase) Preliminary Evaluation Report (ITS) (final) Preliminary 23-June-2017 Evaluation Report developed for Long Y 7/05/2018 Term Electricity Generation (ITS phase) Minute (Purchase Recommendation – ED Purchase 19-October-2017 EPIT to Chair APU) – Long Term Electricity Recommendation Generation (Final Signed) developed for Long Term Electricity Y 7/05/2018 Generation (ITS phase) to inform APU that State decided to

discontinue the tender process

Diagram N/a dEPICting the high Y 18/05/2018 level governance High level governance diagram structure Terms of N/a References for Y 18/05/2018 Terms of Reference documents for EPIC and EPIC and EPIT - EPIT signed Minutes and Multiple accompanying presentation Y 18/05/2018 relating to generator purchase Minutes and Presentation from EPIC options (redacted) Report prepared by 20-July-2017 Aurecon relating to the Emergency Gas Y 18/05/2018 Generation Project Aurecon Report titled Permanent Facility Cost - Permanent Study_Final Draft 20 July 17 Facility Extract from STCC N/a relating to the establishment and Y 18/05/2018 role of the Steering STCC extract Committee Listing of power N/a stations in SA along with the Y 18/05/2018 corresponding AEMO - owner and Generation_Information_SA_March_2018 nameplate capacity Submission to SPB 12-April-2017 prepared by the SPB secretariat Y 25/05/2018 regarding Submission to SPB - Temporary Generator - temporary 12 April 2017 generator Approval from 13-April-2017 SPB regarding Y 25/05/2018 Approval from SPB - Temporary Generator - temporary 13 April 2017 generator Submission to SPB 12-April-2017 prepared by the SPB secretariat Y 25/05/2018 regarding Submission to SPB - Permanent Generator - permanent 12 April 2017 generator Approval from 13-April-2017 SPB regarding Y 25/05/2018 Approval from SPB - Permanent Generator - temporary 13 April 2017 generator

Email to SPB 22-June-2017 prepared by the SPB secretariat Y 25/05/2018 regarding FW Gas-Fired Electricity Generation Plant - permanent Additional Detail generator Attachment to 22-June-2017 email - Evaluation Y 25/05/2018 EP - Long Term Electricity Generation (ITS) Plan (Final Signed) Attachment to 22-June-2017 State Energy Plan Risk Register - 20170616 - email - Risk Y 25/05/2018 SPB Register Minute (Acquisition Plan - Chair APU to CE) Minute to CE 05-January-2018 - Permanent Emergency Power Plant (Signed) requesting approval (1) of the Acquisition Y 25/05/2018 Plan for Permanent Emergency Power Plant Acquisition Plan – Permanent Emergency Acquisition Plan ################ Power Plant (Final Signed) (1) for Permanent Emergency Power Y 25/05/2018 Plant procurement approved by relevant delegates Letter (Acquisition Plan – CE to SPB) – Letter to SPB from 05-January-2018 Permanent Emergency Power Plant (Signed) CE requesting approval of the Acquisition Plan Y 25/05/2018 for Permanent Emergency Power Plant Submission to SPB 10-January-2018 prepared by the SPB secretariat Y 25/05/2018 Submission to SPB - Generator Relocation - regarding generator 10 January 2018 relocation Response from 19-January-2018 SPB regarding generator relocation Y 25/05/2018 requesting Response from SPB - Generator Relocation - additional 19 January 2018 information Minute (Acquisition Plan - Chair APU to CE) Minute to CE 08-February-2018 - State Owned Emergency Power Plant requesting approval (Signed) (2) of the Acquisition Y 25/05/2018 Plan for State Owned Emergency Power Plant Acquisition Plan – Permanent Emergency Updated 08-February-2018 Power Plant (Final Signed) (2) Acquisition Plan for Permanent Emergency Power Y 25/05/2018 Plant procurement approved by relevant delegates

Letter (Acquisition Plan – CE to SPB) – State Letter to SPB from 08-February-2018 Owned Emergency Power Plant (Signed) (2) CE requesting approval of the Acquisition Plan Y 25/05/2018 for Permanent Emergency Power Plant Schedule of changes from previous submision Schedule outlining 08-February-2018 - Feb 2018 changes from the previously Y 25/05/2018 submitted Acquisition Plan Submission to SPB 05-February-2018 prepared by the SPB secretariat Y 25/05/2018 Submission to SPB - Generator Relocation - 5 regarding generator February 2018 relocation Approval from 08-February-2018 SPB regarding Y 25/05/2018 Approval from SPB - Generator Relocation - 8 generator February 2018 relocation Evaluation Plan - State Owned Emergency Evaluation Plan 09-March-2018 Power Plant (Final Signed) developed for State Y 25/05/2018 Owned Emergency Power Plant 171009 SPB presentation PowerPoint 09-October-2017 presentation dated 9 October 2017 prepared for the Y 14/06/2018 State Procurement Board meeting but not presented. State Procurement Board - 20171009 with Word document 09-October-2017 meeting request included dated 9 October summarising the key points discussed at the State Procurement Y 14/06/2018 Board meeting, which was provided to the Board after the meeting. DPC Letter - 2017_09_26 Letter to Don Letter from the 03-January-2018 Russell OCE - SA Government Energy… then A/Chief Executive DPC to the State Y 14/06/2018 Procurement Board dated 3 January 2018, providing a further update