OFFSHORE PETROLEUM AND GREENHOUSE GAS STORAGE (REGULATORY LEVIES) AMENDMENT (TITLES ADMINISTRATION) REGULATIONS 2021 (F2021L01746) EXPLANATORY STATEMENT

Details of the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Amendment (Titles Administration) Regulations 2021

Section 1 - Name

This section specifies that the name of this instrument is the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Amendment (Titles Administration) Regulations 2021 (the Amendment Regulations).

Section 2 - Commencement

This section outlines the commencement information for the provisions of the Amendment Regulations. The Amendment Regulations commence at the same time as Schedule 1 to the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Amendment Act 2021 (the Levies Amendment Act) commences. This Schedule of the Levies Amendment Act provides for the trailing liability measure in relation to cost recovery.

Section 3 - Authority

This section provides that the Amendment Regulations are made under the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Act 2003 (the Levies Act).

Section 4 - Schedules

This section is a machinery clause that provides that the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Regulations 2004 (the Levies Regulations) are amended or repealed as set out in the applicable items in the Schedule, and any other item in the Schedule has effect according to its terms.

Schedule 1 - Amendments

Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Regulations 2004

Item 1 - Regulation 21

Regulation 21 of the Levies Regulations sets out the manner for working out the amount of safety case levy for a facility located, or proposed to be located, in Commonwealth waters.

Regulation 21 includes references to subsection 7(5) of the Levies Act, which provided that the amount of safety case levy imposed by subsection 7(1) in respect of a part of a year is the amount that is worked out in accordance with the Levies Regulations.

The Levies Amendment Act amended the Levies Act so that safety case levy imposed by subsection 7(1) is only imposed in respect of a year, and is no longer imposed in respect of a part of a year. The amendments included repeal of subsection 7(5).

This item amends regulation 21 of the Levies Regulations by omitting references to "subsections 7(4) and (5)", wherever these references occur, and substitutes these references with "subsection 7(4)", to reflect the repeal of subsection 7(5) of the Levies Act.

Items 2 to 4 - Subregulations 22(1) and 22(2)

Regulation 22 of the Levies Regulations provides a mechanism whereby the amount of safety case levy collected in relation to a safety case for a facility located, or proposed to be located, in Commonwealth waters may be varied during the course of a year so as to reconcile the amounts invoiced in advance with the amounts that should, as events have turned out, have been invoiced.

Regulation 22 includes a reference to subsection 7(5) of the Levies Act, which provided that the amount of safety case levy imposed by subsection 7(1) in respect of a part of a year is the amount that is worked out in accordance with the Levies Regulations.

Items 2 to 4 amend regulation 22 to reflect the repeal of subsection 7(5) of the Levies Act and that levy is no longer imposed in respect of part of a year. Item 2 amends subregulation 22(1) by omitting the reference to "subsections 7(4) and (5)" and replaces this reference with "subsection 7(4)". Item 3 amends subregulation 22(1) by omitting the reference to "or part of a year". Item 4 amends subregulation 22(2) by omitting references to "or part of a year", wherever these references occur.

Item 5 - Paragraph 25(1)(b)

Regulation 25 of the Levies Regulations provides for the remittal or refund of part of an amount of safety case levy for a mobile facility in respect of a year, or a part of a year.

The Levies Amendment Act amended the Levies Act so that safety case levy imposed by subsection 7(1) is only imposed in respect of a year, and is no longer imposed in respect of a part of a year.

As a consequence, this item amends paragraph 25(1)(b) of the Levies Regulations by omitting the reference to ", or a part of a year".

Item 6 - Regulation 29

Regulation 29 of the Levies Regulations sets out the manner for working out the amount of safety case levy for a facility located, or proposed to be located, in the designated coastal waters of a State or the Northern Territory.

Regulation 29 includes references to subsection 8(5) of the Levies Act, which provided that the amount of safety case levy imposed by subsection 8(1) in respect of a part of a year is the amount that is worked out in accordance with the Levies Regulations.

The Levies Amendment Act amended the Levies Act so that the safety case levy imposed by subsection 8(1) is only imposed in respect of a year, and is no longer imposed in respect of a part of a year. The amendments included repeal of subsection 8(5).

This item amends regulation 29 by omitting references to "subsections 8(4) and (5)", wherever these references occur, and substitutes them with "subsection 8(4)" to reflect the repeal of subsection 8(5) of the Levies Act.

Items 7 to 9 - Subregulations 30(1) and (2)

Regulation 30 of the Levies Regulations provides a mechanism whereby the amount of safety case levy collected in relation to a safety case for a facility located, or proposed to be located, in State/Northern Territory designated coastal waters may be varied during the course of a year so as to reconcile the amounts invoiced in advance with the amounts that should, as events have turned out, have been invoiced.

Regulation 30 includes a reference to subsection 8(5) of the Levies Act, which provided that the amount of safety case levy imposed by subsection 8(1) in respect of a part of a year is the amount that is worked out in accordance with the Levies Regulations.

Items 7 to 9 amend regulation 30 to reflect the repeal of subsection 8(5) of the Levies Act and that levy is no longer imposed in respect of a part of a year. Item 7 amends subregulation 30(1) by omitting the reference to "subsections 8(4) and (5)" and replaces this reference with "subsection 8(4)". Item 8 amends subregulation 30(1) by omitting the reference to "or part of a year". Item 9 amends subregulation 30(2) by omitting the references to "or part of a year", wherever these references occur.

Item 10 - Paragraph 33(1)(b)

Regulation 33 of the Levies Regulations provides for the remittal or refund of part of an amount of safety case levy for a mobile facility in respect of a year, or a part of a year.

The Levies Amendment Act amended the Levies Act so that the safety case levy imposed by subsection 8(1) is only imposed in respect of a year, and is no longer imposed in respect of a part of a year

As a consequence, this item amends paragraph 33(1)(b) of the Levies Regulations by omitting the reference to ", or a part of a year".

Item 11 - Subregulation 59C(1) (at the end of the note)

Regulation 59C of the Levies Regulations sets out the manner for working out the amount of environment plan levy, which is imposed by section 10F of the Levies Act on the submission of an environment plan, or a proposed revision of an environment plan, in relation to activities authorised by Commonwealth titles.

The Levies Amendment Act amends section 10F of the Levies Act to impose environment plan levy if an environment plan, or a proposed revision of an environment plan, is submitted to NOPSEMA, and the activities to which the plan or revised plan relates are carried out for the purpose of complying with a remedial direction (see items 14 to 16 of Schedule 1 to the Levies Amendment Act).

The note at the end of subregulation 59C(1) explains the operation of section 10F of the Levies Act. This item amends the note by adding ", or are carried out for the purposes of complying with a remedial direction" at the end of the note. This amendment reflects the amendments to section 10F of the Levies Act by explaining that this section also relates to an environment plan, or a proposed revision of an environment plan, in relation to activities carried out for the purpose of complying with a remedial direction.

Item 12 - Subregulation 59G(1) (at the end of the note)

Regulation 59G of the Levies Regulations sets out the manner for working out the amount of environment plan levy, which is imposed by section 10G of the Levies Act on the submission of an environment plan, or a proposed revision of an environment plan, in relation to activities authorised by State/Territory titles.

The Levies Amendment Act amends section 10G of the Levies Act to impose environment plan levy if an environment plan, or a proposed revision of an environment plan, is submitted to NOPSEMA, and the activities to which the plan or revised plan relates are carried out for the purpose of complying with a State/Territory remedial direction (see items 17 to 19 of Schedule 1 to the Levies Amendment Act).

The note at the end of subregulation 59G(1) explains the operation of section 10G of the Levies Act. This item amends the note by adding ", or are carried out for the purposes of complying with a State/Territory remedial direction" at the end of the note. This amendment reflects the amendments to section 10G of the Levies Act by explaining that this section also relates to an environment plan, or a proposed revision of an environment plan, in relation to activities carried out for the purpose of complying with a State/Territory remedial direction.

Item 13 - Regulation 64 (after table item 12)

Regulation 64 of the Levies Regulations prescribes regulations, or provisions of regulations, that are made under the OPGGS Act, for the purposes of particular provisions of the Levies Act.

This item inserts new items 12A and 12B into the table in regulation 64. Table item 12A provides that, for the purpose of subparagraph 10F(1)(d)(i) of the Levies Act, regulation 9 of the Environment Regulations is the prescribed provision, while table item 12B provides that, for the purpose of subparagraph 10F(1)(e)(i) of the Levies Act, regulation 17, 18 or 19 of the Environment Regulations is the prescribed provision.

Paragraphs 10F(1)(d) and (e) were inserted by the Levies Amendment Act (see item 15 of Schedule 1), and impose environment plan levies on the submission of an environment plan, or a proposed revision of an environment plan, to NOPSEMA under a prescribed provision of regulations made under the OPGGS Act, in which the activities to which the plan relates are carried out for the purposes of complying with a remedial direction.

Regulation 9 of the Environment Regulations, which enables an environment plan to be submitted to NOPSEMA for an activity, is the prescribed provision for the purpose of subparagraph 10F(1)(d)(i). This would include an activity carried out for the purposes of complying with a remedial direction.

Regulations 17, 18 and 19 of the Environment Regulations, which enable a proposed revision of an environment plan to be submitted to NOPSEMA for an activity, are the prescribed provisions for the purpose of subparagraph 10F(1)(e)(i). This would include an activity carried out for the purposes of complying with a remedial direction.

Item 14 - Regulation 64 (at the end of the table)

Regulation 64 of the Levies Regulations prescribes regulations, or provisions of regulations, that are made under the OPGGS Act, for the purposes of particular provisions of the Levies Act.

This item inserts new items 16 and 17 into the table in regulation 64. Table item 16 provides that, for the purpose of subparagraph 10G(1)(d)(i) of the Levies Act, regulation 9 of the Environment Regulations is the prescribed provision, while table item 17 provides that, for the purpose of subparagraph 10G(1)(e)(i) of the Levies Act, regulation 17, 18 or 19 of the Environment Regulations is the prescribed provision.

Paragraphs 10G(1)(d) and (e) were inserted into the Levies Act by the Levies Amendment Act (see item 18 of Schedule 1) and impose environment plan levies on the submission of an environment plan, or a proposed revision of an environment plan, to NOPSEMA under a regulation of a State or Territory that substantially corresponds to a prescribed provision of regulations made under the OPGGS Act, in which the activities to which the plan relates are carried out for the purposes of complying with a State/Territory remedial direction.

The definition of a State/Territory remedial direction was inserted into the Levies Act by the Levies Amendment Act (see item 1 of Schedule 1) and means a direction under a provision of a State PSLA or Territory PSLA that substantially corresponds to section 586, 586A, 587, 587A, 591B, 592, 594A or 595 of the OPGGS Act. Part 6.9 of the OPGGS Act defines the State PSLA of each State and the Territory PSLA of the Northern Territory (see section 643).

Regulation 9 of the Environment Regulations, which enables an environment plan to be submitted to NOPSEMA for an activity, is the prescribed provision for the purpose of subparagraph 10G(1)(d)(i). This would include an activity carried out for the purposes of complying with a State/Territory remedial direction.

Regulations 17, 18 and 19 of the Environment Regulations, which enable a proposed revision of an environment plan to be submitted to NOPSEMA for an activity, are the prescribed provisions for the purpose of subparagraph 10G(1)(e)(i). This would include an activity carried out for the purposes of complying with a State/Territory remedial direction.

Item 15 - After Part 12A

This item inserts new Part 12B into the Levies Regulations, which provides for new regulations 64A and 64B.

New regulation 64A - application of the Levies Regulations if a remedial direction is in force

New subregulation 64A(1) provides that regulation 64A applies if a direction is in force under section 586, 586A, 587 or 587A of the OPGGS Act (referred to as a petroleum remedial direction) or section 591B, 592, 594A or 595 of the OPGGS Act (referred to as a greenhouse gas remedial direction).

Under the OPGGS Act, a remedial direction may be given to a person who is not the current holder of a title. In the case of a remedial direction that applies to a pipeline, this would include a person who is not the pipeline licensee in relation to the pipeline. The Levies Act provides that safety case levy imposed on a safety case in force in relation to a pipeline to which a remedial direction applies is payable by the person who is subject to the remedial direction. That person may be the pipeline licensee or another person.

New subregulation 64A(2) provides that regulation 4 only applies to a pipeline licensee. This means that, if a remedial direction is in force in respect of a pipeline and the person who is subject to the direction is not the pipeline licensee, regulation 4 does not apply to the person. Such persons may include a former licensee of the pipeline licence, a related body corporate of the pipeline licensee or a former licensee of the pipeline licence, or a person to whom a determination under subsection 586(2B), 586A(2B), 587(2B), 587A(2B), 591B(2B), 592(2B), 594A(2B) or 595(2B) applies (referred to as a person who is subject to a 'related person' determination).

Regulation 4 ensures, in circumstances where a pipeline is partly in Commonwealth waters and partly in State/Territory designated coastal waters, that the pipeline licensee will only pay the safety case levy once with respect to the jurisdiction where the length of the pipeline is predominantly located.

In the case of a remedial direction given to a person who is not the pipeline licensee, the person who is subject to the direction would be only undertaking work on the part of the pipeline located in Commonwealth waters (as a direction under the OPGGS Act can only require action in Commonwealth waters). Unlike a pipeline licensee, the person who is subject to the direction would therefore only have a safety case in relation to the part of the pipeline in Commonwealth waters. If regulation 4 applied to a person who is not the pipeline licensee and the length of the pipeline was predominantly located in designated coastal waters, no levy would be payable to NOPSEMA in respect of the safety case for decommissioning the pipeline in Commonwealth waters.

Excluding the application of regulation 4 to a person who is not the pipeline licensee ensures that such a person is required to pay the safety case levy in respect of decommissioning the segment of the pipeline in Commonwealth waters, regardless of where the length of the pipeline is predominantly located.

New subregulations 64A(3) to (5) operate by deeming a reference to certain terms in specified provisions of the Levies Regulations to include a reference to other terms if a remedial direction is in force. This provides for the application of the provisions of the Levies Regulations that relate to safety case levies, well activity levies and environment plan levies imposed by the Levies Act in relation to persons who are subject to a remedial direction.

Under new subregulation 64A(3), if a remedial direction is in force, Division 2 of Part 10 and regulations 59C and 62 of the Levies Regulations apply:

* as if a reference to a registered holder of an eligible title that is a petroleum title included a reference to a person who is subject to a petroleum remedial direction; and

* as if a reference to a registered holder of an eligible title that is a greenhouse gas title included a reference to a person who is subject to a greenhouse remedial direction.

In addition, under new subregulation 64A(5), if a remedial direction is in force, Part 11B, excluding regulation 59B, of the Levies Regulations applies as if:

* a reference to an individual activity included a reference to an activity that is of the same kind as a petroleum activity set out in the table in subregulation 59C(7), and carried out for the purpose of complying with a petroleum remedial direction; and

* a reference to a licensed petroleum pipeline included a reference to a pipeline in relation to which a petroleum remedial direction applies.

The effects of these new subregulations are as follows:

* Section 10C of the Levies Act imposes well activity levy if a person who is subject to a remedial direction submits a well operations management plan, or a proposed revision of a well operations management plan, to NOPSEMA under Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011 (the RMA Regulations) in relation to an activity relating to a well carried out for the purpose of complying with the direction. New subregulation 64A(3) provides for the application of Division 2 of Part 10 of the Levies Regulations in relation to the person. This Division prescribes the amount of well activity levy imposed on the submission of the plan or revised plan, and provides when the levy is due and payable.

* Section 10F of the Levies Act imposes environment plan levy on the submission of an environment plan, or a proposed revision of an environment plan, to NOPSEMA under the Environment Regulations in relation to an activity or activities carried out for the purpose of complying with a remedial direction. The levy is payable by the person who is subject to the remedial direction. New subregulations 64A(3) and (5) provide for the application of Part 11B of the Levies Regulations, excluding regulation 59B, in relation to the person.

* Part 11B sets out the manner for working out the amount of environment plan levy on the submission of the plan or revised plan (see regulation 59C) and also sets out, amongst other matters, when the levy is due and payable.

* Regulation 59B is excluded as it not necessary to deem the specified references in the definitions to include references to other terms if a remedial direction is in force.

Under new subregulation 64A(4), if a remedial direction is in force, the definition of SMS amount in regulation 3, Divisions 2 and 3 of Part 4, regulation 62 and Part 2 of Schedule 3 to the Levies Regulations apply as if a reference to a licensee or licensee of a pipeline licence included a reference to a person who is subject to a petroleum or greenhouse gas remedial direction.

Section 7 of the Levies Act imposes safety case levy in respect of a year if a safety case is in force at the start of the year, or during part of the year but not at the start of the year, for a facility (including a pipeline) located, or proposed to be located, in Commonwealth waters. The effect of new subregulation 64A(4) is to provide for the manner in which relevant provisions of the Levies Regulations apply to a person who is subject to a remedial direction in respect of the levy, if a remedial direction is in force in relation to a facility that is a pipeline in Commonwealth waters and safety case levy is imposed on a safety case for the facility. This includes Part 4 of the Levies Regulations, which sets out, amongst other things, the manner for working out the amount of safety case levy that is imposed, and when the levy is due and payable. In addition, the definition of SMS amount in regulation 3 is relevant to determining the amount of safety case levy imposed on a safety case for a facility that is a pipeline (see subregulation 21(1A)). Part 2 of Schedule 3 provides for the SMS amount.

Subregulations 64A(3) and (4) also provide for the manner in which regulation 62 applies to a levy payer that is a person who is subject to a remedial direction. Regulation 62 requires the Chief Executive Officer of NOPSEMA to prepare a financial report in respect of each financial year that assesses the cost effectiveness of the operations of NOPSEMA in that financial year, and to give a copy of the report to levy payers. Subregulations 64A(3) and (4) ensure that a report must also be given to a person who is subject to a remedial direction who has been required to pay levy in the financial year.

If a person is a current titleholder subject to a remedial direction under section 586, 586A, 591B or 592, the Levies Regulations continue to apply to that person as a titleholder. The amendments ensure extended application of relevant provisions of the Levies Regulations if a remedial direction is given to a person other than the current titleholder.

New regulation 64B - application of the Levies Regulations if a State/Territory remedial direction is in force

New subregulation 64B(1) provides that regulation 64B applies if a direction is in force under a provision of a State PSLA or Territory PSLA that substantially corresponds to section 586, 586A, 587 or 587A of the OPGGS Act (referred to as a State/Territory petroleum remedial direction) or section 591B, 592, 594A or 595 of the OPGGS Act (referred to as a State/Territory greenhouse gas remedial direction). Part 6.9 of the OPGGS Act defines the State PSLA of each State and the Territory PSLA of the Northern Territory (see section 643).

New subregulation 64B(2) provides that regulation 4 only applies to a pipeline licensee. This means that, if a remedial direction is in force in respect of a pipeline and the person who is subject to the direction is not the pipeline licensee, regulation 4 does not apply to the person. Such persons may include a former licensee of the pipeline licence, a related body corporate of the pipeline licensee or a former licensee of the pipeline licence, or a person to whom a determination under subsection 586(2B), 586A(2B), 587(2B), 587A(2B), 591B(2B), 592(2B), 594A(2B) or 595(2B) applies (referred to as a person who is subject to a 'related person' determination).

In the case of a State/Territory remedial direction given to a person who is not the pipeline licensee, the person who is subject to the direction would be only undertaking work on the part of the pipeline located in designated coastal waters (as a direction under a State PSLA or Territory PSLA can only require action in the relevant State or Territory waters). Unlike a pipeline licensee, the person who is subject to the direction would therefore only have a safety case in relation to the part of the pipeline in designated coastal waters. If regulation 4 applied to a person who is not the pipeline licensee, and the length of the pipeline was predominantly located in Commonwealth waters, no levy would be payable to NOPSEMA in respect of the safety case for decommissioning the pipeline in designated coastal waters.

Excluding the application of regulation 4 to a person who is not the pipeline licensee ensures that such a person is required to pay the safety case levy in respect of decommissioning the segment of the pipeline in designated coastal waters, regardless of where the majority of the pipeline is located.

New subregulations 64B(3) to (5) operate by deeming a reference to certain terms in specified provisions of the Levies Regulations to include a reference to other terms if a State/Territory remedial direction is in force. This provides for the application of the provisions of the Levies Regulations that relate to safety case levies, well activity levies and environment plan levies imposed by the Levies Act in relation to persons who are subject to a State/Territory remedial direction.

Under new subregulation 64B(3), if a State/Territory remedial direction is in force, Division 2 of Part 11 and regulations 59G and 62 of the Levies Regulations apply:

* as if a reference to a registered holder of a State/Territory title that is a State/Territory petroleum title included a reference to a person who is subject to a State/Territory petroleum remedial direction; and

* as if a reference to a registered holder of a State/Territory title that is a State/Territory greenhouse gas title included a reference to a person who is subject to a State/Territory greenhouse remedial direction.

In addition, under new subregulation 64B(5), if a State/Territory remedial direction is in force, Part 11C, excluding regulation 59F, of the Levies Regulations applies as if:

* a reference to an individual activity included a reference to an activity that is of the same kind as a petroleum activity set out in the table in subregulation 59G(7), and carried out for the purpose of complying with a State/Territory petroleum remedial direction; and

* a reference to a licensed petroleum pipeline included a reference to a pipeline in relation to which a State/Territory petroleum remedial direction applies.

The effects of these new subregulations are as follows:

* Section 10D of the Levies Act imposes well activity levy if a person who is subject to a State/Territory remedial direction submits a well operations management plan, a proposed revision of a well operations management plan, or an application for approval to commence an activity relating to a well to NOPSEMA under regulations of a State or Territory that substantially correspond to Part 5 of the RMA Regulations in relation to an activity relating to a well carried out for the purpose of complying with the direction. New subregulation 64B(3) provides for the application of Division 2 of Part 11 of the Levies Regulations in relation to the person. This Division prescribes the amount of well activity levy imposed on the submission of the plan, revised plan or application, and provides when the levy is due and payable.

* Section 10G of the Levies Act imposes environment plan levy on the submission of an environment plan, or a proposed revision of an environment plan, to NOPSEMA under a regulation of a State or Territory that substantially corresponds to the Environment Regulations in relation to an activity or activities carried out for the purpose of complying with a State/Territory remedial direction. The levy is payable by the person who is subject to the direction. New subregulations 64B(3) and (5) provide for the application of Part 11C of the Levies Regulations, excluding regulation 59F, in relation to the person.

* Part 11C sets out the manner for working out the amount of environment plan levy on the submission of the plan or revised plan (see regulation 59G) and also sets out, amongst other matters, when the levy is due and payable.

* Regulation 59F is excluded as it is not necessary to deem the specified references in the definitions to include references to other terms if a State/Territory remedial direction is in force.

Under new subregulation 64B(4), if a State/Territory remedial direction is in force, the definition of SMS amount in regulation 3, Divisions 2 and 3 of Part 5, regulation 62 and Part 2 of Schedule 3 to the Levies Regulations apply as if a reference to a licensee or licensee of a pipeline licence included a reference to a person who is subject to a State/Territory petroleum remedial direction or a State/Territory greenhouse gas remedial direction.

Section 8 of the Levies Act imposes safety case levy in respect of a year if a safety case is in force at the start of the year, or during part of the year but not at the start of the year, for a facility (including a pipeline) located, or proposed to be located, in the designated coastal waters of a State or of the Northern Territory. The effect of new subregulation 64B(4) is to provide for the manner in which relevant provisions of the Levies Regulations apply to a person who is subject to a State/Territory remedial direction in respect of the levy, if a State/Territory remedial direction is in force in relation to a facility that is a pipeline in designated coastal waters and safety case levy is imposed on a safety case for the facility. This includes Part 5 of the Levies Regulations, which sets out, amongst other things, the manner for working out the amount of safety case levy that is imposed, and when the levy is due and payable. In addition, the definition of SMS amount in regulation 3 is relevant to determining the amount of safety case levy imposed on a safety case for a facility that is a pipeline (see subregulation 29(1A)). Part 2 of Schedule 3 provide for the SMS amount.

Subregulations 64B(3) and (4) also provide for the manner in which regulation 62 applies to a levy payer that is a person who is subject to a State/Territory remedial direction. Regulation 62 requires the Chief Executive Officer of NOPSEMA to prepare a financial report in respect of each financial year that assesses the cost effectiveness of the operations of NOPSEMA in that financial year, and to give a copy of the report to levy payers. Subregulations 64B(3) and (4) ensure that a report must also be given to a person who is subject to a State/Territory remedial direction who has been required to pay levy in the financial year.

If a person is a current State/Territory titleholder subject to a remedial direction under a provision of a State PSLA or Territory PSLA that substantially corresponds to section 586, 586A, 591B or 592, the Levies Regulations continue to apply to that person as a titleholder. The amendments ensure extended application of relevant provisions of the Levies Regulations if a State/Territory remedial direction is given to a person other than the current titleholder.

Item 16 - Schedule 2 (note)

Schedule 2 describes mobile facilities.

The note at Schedule 2 explains that regulations 25 and 33 provide for when part of an amount of a safety case levy imposed in respect of a mobile facility and a year, or a part of a year, must be remitted or refunded.

The Levies Amendment Act amended the Levies Act so that the safety case levy is only imposed in respect of a year, and is no longer imposed in respect of a part of a year. This item omits ", or a part of a year," from the note as a consequence of the amendments made by the Levies Amendment Act.

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Content contained herein should be attributed as Regulatory Impact Statement: Improvements to Title Administration, October 2020, Australian Government Department of Industry, Science, Energy and Resources.

ISBN: 978-1-922125-77-4

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Contents

Preamble. 4

1. The Problem.. 6

2. Need for government action. 8

3. Potential policy options. 9

4. Net benefits. 11

5. Consultation. 16

6. Preferred option. 20

7.� Implementation. 22

Annex 1: Costing Assumptions. 24

Annex 2: Table of Key Implementation Risks. 25

Preamble

The resources sector is instrumental to Australia's economic prosperity. The significant employment and economic activity generated by the sector has helped sustain Australia's development and growth over the last two decades. The Australian Government's vision is to have the world's most advanced, innovative and successful resources sector, which delivers sustained prosperity and social development for all Australians. It aims to deliver the most globally attractive and competitive investment destination for resources projects to facilitate Australia's economic growth and innovation, into the future.

Australia has a globally recognised oil and gas sector, which has made significant economic contributions to the economy. Australia's oil and gas industry has delivered enormous benefits in the form of export earnings, domestic economic activity, employment and investment. It has also created and sustained a globally respected and innovative technology, services and manufacturing sector. According to the Resources and Energy Quarterly September 2020, Australia remains one of the world's largest exporters of Liquefied Natural Gas, accounting for approximately AUD$31 billion in export revenue in 2020-2021.^{^[1]}

A key policy objective of the offshore regime is to ensure that Australia's resources are developed sustainably, responsibly and in accordance with industry leading practice. This means that resource management, the environment and the health and safety of those employed in the sector, are key considerations for petroleum activities that are undertaken within the regime. It is also important that the risks and liabilities of petroleum activities, remain the responsibility of those who have derived the financial benefits from the project, rather than the Commonwealth and the Australian taxpayer. The Commonwealth seeks to balance these considerations and the continuous improvement of the regulatory framework, all while minimising the regulatory burden on business.

Australia's offshore regime is now maturing as some projects and basins begin to plateau and may decline if new fields are not brought in to production. The late 1960s saw the offshore Gippsland Basin start production and the 1970s saw oil discovered off the northern coast of Western Australia, which is now also a highly productive gas province and has become the cornerstone of the Australian oil and gas industry. The regime is currently geared towards attracting new investment and discovery of Australian resources, with its regulatory framework reflecting these priorities. However, as the industry matures, projects are coming to an end, requiring greater regulatory emphasis on activities which occur in the mid to end of life phase of the project. The framework must therefore adapt to the changing needs of industry to effectively manage petroleum activities that are common in the mid to end of a project's life. Such activities include (but are not limited to) transfers of titles, changes of ownership and decommissioning.

The recent liquidation of the Northern Oil and Gas Australia (NOGA) group of companies demonstrated the importance of the offshore regulatory framework adapting to the needs of the offshore industry. In an unprecedented event throughout the 50 years of Australia's offshore regime, the NOGA group of companies went into liquidation on 7 February 2020, with an offshore facility that until July 2019, had been in production.

Having purchased the asset and titles from Woodside Energy via a corporate transfer in 2016, NOGA is an example of a company entering the regime towards the end of the project's life, when production was declining. The NOGA liquidation highlighted the need for the framework to provide greater regulatory oversight throughout the life of a project.

The department is seeking to amend the regulatory framework to strengthen the requirements for entities entering and progressing through the regime to ensure they are suitable, including being financially and technically capable to undertake petroleum activities in a safe manner and ensure that the environment is rehabilitated in compliance with the Offshore Petroleum and Greenhouse Gas Storage Act 2006 Act (the Act). The department also wants to ensure those entering the regime do not have a history of material non-compliance, fraudulent or misleading behaviour and/or financial mismanagement. While regulatory amendments cannot entirely prevent a situation where a company suffers financial distress, providing increased regulatory oversight at key gateway points can ensure those entering the regime to be both capable and appropriate to undertake their obligations and meet liabilities, effectively managing the risk to the Commonwealth.

1. The Problem

Problem Statement

The current offshore regulatory framework lacks sufficient mechanisms, particularly at certain high risk gateways, to ensure that an entity is appropriate to become a titleholder in Australia's offshore regime and undertake petroleum activities.

As Australia's offshore industry matures, there are an increasing number of projects and assets reaching end of life in the next 30 years, with an anticipated decommissioning liability of AUD$60 billion.^{^[2]} The regulatory framework and the posture of the regulator, will need adapt to meet the changing needs of the Australian offshore industry, which is beginning to focus more on mid-to-end of life petroleum activities, while also remaining attractive to encourage new investment in the regime.

A change in ownership and control of a titleholder may result in an unsuitable entity becoming a titleholder in the Australian offshore regime.

Commercial transactions to sell or acquire oil and gas assets and titles can be structured in a variety of manners. Currently, the Act requires the assessment and registration of two classes of transactions by the National Offshore Petroleum Titles Administrator (NOPTA) - 'transfers' and 'dealings'.

In seeking approval for a transfer, the applicant must provide financial and technical information to NOPTA, who is able to exercise information gathering powers to obtain further documentation from the applicant. However, there is a lack of regulatory oversight of transactions involving a change in the ownership or control of titleholders. This generally occurs via parent company acquisitions of the shares in titleholders (who tend to be subsidiaries within corporate groups). This effectively changes the company structure but is not captured by the legislation as a 'transfer' of a title or a 'dealing' because no interests in the title itself are transferred, created or assigned. Such transactions are a common way for the industry to sell ownership of offshore projects.

This results in a risk that entities that are not suitable or capable can enter the regime where a producing asset is acquired 'indirectly' through a change in the ownership or control of the titleholder (the entity that holds the interests in the title itself). This risk increases late in the life of the title due to declining production, resulting in an uncertain revenue stream, and potentially resulting in the costs of decommissioning being beyond the financial capacity of the titleholder.

There is insufficient clarity and/or transparency of decision-making criteria at key gateway points to determine whether an entity is suitable to enter Australia's offshore regime.

Good decision-making builds in accountability that applies to the decision-maker by ensuring the merits of each case are considered against criteria. Currently, there is a lack of clarity around the regulator's decision-making criteria (allowing for broad discretion) at key gateway points, other than the initial entry application into the regime. These decisions determine whether a titleholder is appropriate to enter Australia's offshore regime.

As projects mature, there is the increased probability of existing titleholders looking to sell its title and/or assets, as the viability of the project starts to diminish as a result of the declining resources and increasing costs. While this may provide an investment opportunity for companies with lower overheads to extract the remaining resource, the regulator's decision making process as to whether a titleholder is appropriate and capable to undertake these activities and enter the regime, remains unclear. This includes a lack of clarity around the requirements and decision-making criteria that the regulator will consider in deciding whether an applicant is appropriate, financially and technically capable and whether they have a history of compliance and good standing within the regime.

There are limited mechanisms to protect the Australian taxpayer where the titleholder is unable to meet its liabilities or encourage titleholders to undertake their due diligence when disposing of assets/titles.

While the current regulatory framework provides for oversight, there may be unforeseen circumstances (such as a crash in oil price, of extended period of subdued demand during the current pandemic) where despite its best efforts, a titleholder's financial health may deteriorate to such a point that it cannot continue to operate, thereby putting at risk its ability to meet its decommissioning obligations. An inability to properly decommission and remediate a site raises potential risks to the environment without government intervention.

In Australia, the form of 'trailing liability' in the regime is currently limited in its use to a certain set of circumstances. The independent Review of the Circumstances that Led to the Administration of the Northern Oil and Gas Australia (NOGA) Group of Companies by Mr Steve Walker (the Walker Review), highlighted that this limited scope for trailing liability doesn't properly protect the interests of the broader community and taxpayer, and is inconsistent with comparable jurisdictions who are managing a mature industry.

As a result of this limited nature, it means that there is limited ability for the regulator to 'call back' previous titleholders or other related persons in the event the former titleholder no longer exists, who have obtained a financial benefit from the resources. Where a current titleholder suffers financial distress and/or is unable to fulfil its decommissioning liabilities, and all other safeguards have failed, the Government should have the ability to recall a previous titleholder(s) to be involved in decommissioning and/or remediation activities. The Walker Review observed that this ability is available in other jurisdictions and should be considered in the Australian context.

Recognising the ways in which companies are able to structure transactions to divest assets and titles to limit accountability for decommissioning obligations, the department proposes to introduce the concept of a 'related person' for the purposes of trailing liability. A related person will include the former titleholder and a parent company of the current or former titleholder.

The department considers a key policy objective of expanding the existing trailing liability provisions, to be a change in industry behaviour in that outgoing titleholders would undertake greater due diligence checks of who it is selling its assets to, knowing that if the incoming titleholder fails to meets its obligations the outgoing titleholder would be recalled. This is important in reducing the risk that existing titleholders may dispose of mature-late-life assets to entities who may not be financially or technically capable of undertaking the petroleum activities and fulfilling their liabilities.

2. Need for government action

As the Australian offshore regime matures, government action is needed to improve the regulatory framework and address the issues that have been brought to light by the recent NOGA liquidation. Government action is required to undertake continuous improvement of the offshore regulatory framework, which maintains community confidence in the regime and provides for better regulatory outcomes for both the government and the industry.

The financial risks to the Commonwealth and the Australian taxpayer if no action is taken are significant, as offshore resource projects are generally multi-billion dollar investments with assets and liabilities of a similar magnitude and scale. Similarly, the environmental and safety risks if a project is not adequately decommissioned are significant and could result in the pollution and/or damage to the marine environment as well as injury/loss of life to employees or impacts on other users of the marine environment. In addition, government action is needed to ensure that the reputation of Australia's offshore regime is maintained, in line with other leading practice regimes around the world.

The Australian government must take action to improve and increase safeguards against the significant risks to the Commonwealth if offshore projects are unable to be decommissioned by titleholders.

This includes adding clarity and regulatory oversight to decision making criteria, so that the regulator can consider an applicant's appropriateness to take over title interests, assess their capacity to fulfil their financial and technical obligations before they enter the regime and ensure such decisions and requirements are clear and transparent to industry. This assists both the regulator and potential titleholders in understanding the requirements that will be considered to enter the offshore regime.

Government action is required to ensure that where all other safeguards have failed, as an option of last resort, it has the ability to mitigate the risks to itself (and subsequently the Australian taxpayer) by requiring decommissioning liabilities to be met by former titleholders or related persons in the event the former titleholder company no longer exists, who have obtained financial benefits from the resources.

In Australia, this is currently limited in its use to a certain set of circumstances. The Walker Review highlighted that this limited scope does not properly protect the interests of the broader community and taxpayer, and is inconsistent with comparable jurisdictions who are managing a mature industry. It should be noted that in the offshore resources industry, there will always be inherent risks and there is no way in which to completely eliminate the risk of a titleholder experiencing financial distress. However, the department is proposing measures that will provide some safeguards and mechanisms to improve regulatory oversight and reduce the risks as much as possible while maintaining the Australian regime as an attractive investment destination.

3. Potential policy options

Three options have been considered to respond to the problem statement.

A non-regulatory option has not been explored as a possible option. This is because a non-regulatory option does not meet the fundamental requirements for regulatory oversight from the Australian Government for the offshore oil and gas regulatory framework. Removing or diminishing the Australian Government's role in the regulation of offshore petroleum activities poses an unacceptable risk to the industry, environment and the Australian public.

Option 1

In this option, the regime remains as is, the government takes no action and the regulatory framework continues to operate in its current form.

This option means that no Commonwealth resources are required to amend the Act or to undertake increased regulation of the regime. This also means that there is no increase in regulatory burden for industry as there is no change in the regulatory obligations.

Without regulatory amendments, projects within the regime will continue to mature with many reaching their end of life over the next 10 to 50 years. There will be no added regulatory oversight at key gateway points and limited mechanisms for the regulator to call back any previous titleholders to fulfil decommissioning obligations. It is possible that acquiring title interests through a change in ownership or control of a titleholder company will become a preferred entry gateway for entrants into the regime in later project life, as companies can access existing PRRT credits.

Without making regulatory amendments to the existing framework, there are increased risks of the taxpayer being exposed to the costs associated with similar events occurring. Financially, these risks are significant as the liabilities of projects coming to the end of life within the Australian regime are over AUD$60 billion across the next 30 years.^{^[3]} There will also remain risks to the environment and safety of employees where the financial and technical capability of new titleholders are not considered at key gateway points.

Taking no action may result in companies who do not have the financial capacity, being unable to fulfil their environmental and work health and safety requirements under the Act, presenting a risk to the safety of individuals and the environment. It also risks reputational damage to the Australian offshore regime if it does not adapt to meet the evolving needs of the industry and various projects coming to their end of life. As the current regime is lightly tested with regard to decommissioning activities, there are identified opportunities to improve the current regulatory practice with regard to petroleum activities that occur in mid-late life of a title such as sale, transfers and decommissioning.

Under this option, the form of trailing liability would also remain limited with little ability for the government to call back a former titleholder or related person in the event the last remaining titleholder failed to meet its decommissioning obligations. This will retain the status quo and the current behaviour of the industry to offload mature projects to avoid the liabilities attached to those projects.

Option 2

In this option, regulatory amendments are made to increase regulatory oversight of titleholders entering and progressing through the regime, while not stifling investment in the Australian offshore regime. It seeks to balance the tension between providing adequate regulatory oversight and mechanisms to reduce the risks surrounding decommissioning liabilities for new titleholders, while not tying up a company's cash flow towards the end of the project's lifespan, which may result in some companies experiencing financial distress.

Through the proposed regulatory amendments, the regulator will be given clear decision-making criteria to assess, on a case-by-case basis, a new entity applying to enter the regime and consider their financial and technical capability to fulfil their obligations. Using a risk-based approach, the regulator can consider the diverse range of titleholders, assets and projects, which each present varying degrees of risk and liability. This option places the onus on the applicant to demonstrate to Government that they have the capacity and capability to fulfil their obligations.

Increased oversight and clarity around decision-making at key gateway points such as sale, transfer or change of ownership would also provide potential titleholders with transparency around the process, expectations and obligations required to take part in the Australian offshore regime.

This approach seeks to ensure that the regulatory amendments are both reasonable and effective, while creating mechanisms that allow a regulator to mitigate potential risks to the Commonwealth.

The proposed measures in this option would involve the following changes to the Act:

providing clear decision-making criteria for the regulator in assessing capacity and appropriateness at specified high risk gateways, including transfers of titles, and changes in ownership and control relating to titleholders;

- including criteria for participants in the regime (either direct or indirect) to assess their appropriateness to carry out petroleum or GHG storage activities;

- providing that an application or a titleholder will need to demonstrate their financial and technical capability and appropriateness at specified high risk gateways;

enabling regulatory oversight where there is a change of ownership and/or control i.e. ensuring that transaction is subject to the same regulatory requirements as if it is a transfer of title.
expanding the existing trailing provisions to apply in a greater range of circumstances through the issuance of a remedial direction to a former titleholder and/or related person as a last resort option available to government.

- In comparable jurisdictions and given the last resort nature of trailing liability, it has been designed that trailing liability is 'activated' following a series of events and non-compliance by the current titleholder.

Option 3

This option involves NOPTA taking a more intensive approach to regulation to reduce the risk that a titleholder is unable to meet its liabilities.

Here, the same changes as Option 2 would be made to the regulatory framework however, the regulator's oversight of low risk transactions and gateways would also be increased and trailing liability would be a standalone obligation in the Act rather than being a power that is activated by a decision of government. The result of this option is that companies will need to account for its liabilities on an ongoing basis, in some form, despite selling its assets to another party.

This means that rather than giving NOPTA the discretion in assessing these risks on a case-by-case basis, a regulator would require much more information from applicants on each and every transaction during the life of a title.

This option would require:

More detailed information requirements at key gateway points as well as more prescriptive requirements that the regulator would need to consider in making its decision;
Added regulatory oversight of financial and technical capability across all dealings great and small rather than just the key gateway points which present higher risk (for example, where a joint operating agreement between titleholders is amended as opposed to when the title undergoes a change of ownership or transfer at a key gateway);
A fit and proper associates test to assess any individual who may have either direct or indirect influence and or control are scrutinised, where a new titleholder seeks to enter the Australian offshore regime; and
Addition of a 'standing obligation' in the Act that a titleholder may at any time, be recalled to undertake decommissioning and remedial activities.

This approach would be highly burdensome on operators and titleholders and would involve a significantly higher cost to the Commonwealth to ensure compliance, while not necessarily delivering a significant benefit in reducing the risks of decommissioning liabilities being met.

This option may also discourage further investment in Australia.

4. Net benefits

Costing assumptions for the potential policy options are at Annex 1.

Option 1

Option 1 (status quo): $1,895.66 (estimated cost for an organisation to prepare a report) based on 6 hours of time of a technical financial / administration employee at an hourly wage rate of $121.15 and 1 hour of time of 2 CEOs/Directors at a hourly wage rate of $583.33. $644,524.40 (estimated cost across the sector) based on a multiplier of 68 (average number of applications NOPTA receives per FY) and 5 (average JV partners per title).

Regulatory benefit

There are no additional benefits above the existing framework as there is no change.

Regulatory cost

There is no additional regulatory cost associated with this option, as there is no change to the current regulatory framework, therefore no additional burden or impost on the regulator to continue to regulate the framework as it currently stands. There is no change to the cost or burden on industry/titleholders in this option as there is no change in regulation.

Net benefit

There no net benefit in this option as there is no change to the existing regulatory framework.

Other considerations

Without making regulatory improvements to the existing framework, there are increased risks of entities becoming titleholders who are unable to meet their decommissioning obligations, resulting in the risk of a similar event occurring. Failure to decommission may result in safety and environmental impacts unless the Australian Government steps in to decommission and remediate the environment. These risks are significant as Australia's current decommissioning liability over the next 30 years is estimated to be AUD$60 billion^{^[4]} and can have far-reaching consequences for safety and the environment.

While the NOGA liquidation was an unprecedented event, the potential consequences for the Australian taxpayer are significant. This risk will increase as Australia's regime is maturing with many projects nearing the end of life in the near future (next 30-50 years). The likelihood of an operator being unable to fulfil its decommissioning liabilities will therefore increase. Combined with the scale and cost of offshore petroleum projects, the liabilities are significant with limited ability of the government to call back entities.

This option also risks deterioration of community confidence in, and reputational damage to, the Australian industry participants, as well as the government regulator. In addition, titleholders may experience a decline in social licence to operate if other projects are not appropriately decommissioned within the regime. This option increases the risks of an environmental or safety incident if a titleholder is unable to fulfil its liabilities and carry out petroleum activities in accordance with the framework.

Option 2

Summary of regulatory impact calculations

Options	Technical and financial reporting Sector ($m)	Fit and proper person declaration and appropriateness criteria Sector ($m)	Change of ownership and control Sector ($m)	Total annual estimated regulatory costs ($m)	Total estimated regulatory costs over thirty years ($m)*
Option 1:	0.645	-	-	0.645	19.350
Option 2:	0.825	3.151	0.003	3.979	119.370
Change in regulatory costs	0.180	3.151	0.003	3.334	100.020

*A thirty-year period for forecasted regulatory costs has been used due to the extended duration of offshore oil and gas projects.

Option 2 (additional technical and financial reports): $1,895.66 (estimated cost for an organisation to prepare a report) based on 6 hours of time of a technical financial / administration employee at an hourly wage rate of $121.15 and 1 hour of time of 2 CEOs/Directors at a hourly wage rate of $583.33. $824,612.10 (estimated cost across the sector) based on a multiplier of 87 (estimated number of applications NOPTA will receive per FY) and 5 (average JV partners per title).

Option 2 (fit and proper person declaration and appropriateness criteria application): $7,242.96 (estimated cost for an organisation to prepare an application) based on 2 hours of time of a technical financial / administration employee at an hourly wage rate of $121.15 and 1 hour of time of 12 CEOs/Directors at a hourly wage rate of $583.33. $3,150,687.60 (estimated cost across the sector) based on a multiplier of 87 (estimated number of applications NOPTA will receive per FY) and 5 (average JV partners per title).

Option 2 (change of ownership and control application): $1,288.16 (estimated cost for an organisation to prepare an application) based on 1 hours of time of a technical financial / administration employee at an hourly wage rate of $121.15 and 1 hour of time of 2 CEOs/Directors at a hourly wage rate of $583.33. $2,576.32 across the sector with a multiplier of 2 (average number of applications NOPTA receives per FY).

Regulatory benefit

There is regulatory benefit in making the amendments proposed in this option.

Making regulatory amendments to increase regulatory oversight means that there will be increased safeguards in place at key gateway points. This in turn, helps mitigate the risk that liabilities will not be met and are instead, transferred to appropriate entities who have the financial and technical capability to meet those risks. To date, the Australian Government has expended over AUD$75 million to mitigate safety and environmental risks as a result of the liquidation of the NOGA group of companies. Although Option 2 introduces anticipated regulatory impacts for industry, the regulatory benefits would far outweigh these impacts if as few as two similar events occur in the future.

There is also regulatory benefit in providing clarity of decision-making requirements at key gateway points to ensure the process is user-friendly, easy to implement and transparent to all parties. This will ensure that the regulator is better able to manage the expectations of applicants and titleholders and result in an overall better regulatory practice.

The benefit of an expansion of the existing trailing liability provisions is that it achieves the governments outcomes of having the ability to recall previous titleholders ensuring the cost, expenses and liabilities associated with decommissioning are not borne by the Australian community but minimises the extent of how commercial entities must report on and carry the liability on their books.

Regulatory cost

The regulatory cost of this option includes the resourcing and administrative costs involved with amending the regulatory framework and its implementation. In addition, implementing the new regulatory measures would require additional resourcing for the regulator.

This would involve some additional costs to provide additional oversight into matters that are already considered by the regulator (i.e. assessing the financial and technical capability where a titleholder applies to join the regime).

There would be additional regulatory costs to cover regulatory oversight in matters where the regulator would not ordinarily do so (i.e. change in control of a company). This would include resourcing for the purpose of seeking and considering more information from the titleholder or assessing information according to new criteria established by the proposed measures. However these additional responsibilities would only occur at key gateway points in the life of the title (i.e. where the title is sold or transferred) rather than as a regular occurrence (e.g. weekly, monthly or even annually in many cases).

Net benefit

There is a net benefit for this option because the regulatory cost is less than the regulatory benefit. Although the liquidation of the NOGA group of companies was an unprecedented event in the history of Australia's offshore regime, the avoided costs to the Commonwealth and to the Australian taxpayer would far exceed any anticipated regulatory impacts to industry; if the changes where to prevent just two similar situations over the next thirty years.

Other considerations

This option meets the Australian Government's policy objective in continuously improving the offshore resources regime and provides a regulatory framework for industry where liabilities are disposed of responsibly and in line with other best practice regimes.

Costs in relation to trailing liability are only anticipated to result in minimal to nil impact to Australia's overall investment attractiveness; as the associated liability obligations will only be enlivened as a measure of last resort, when all other regulatory mechanisms have failed.

This option also supports industry's social licence to operate as amending the regulatory framework to include better regulatory practices increase community confidence and provide assurances to the Australian community that the regime has environment, safety and financial risks at the forefront of its policy and regulation.

There is a significant risk to the taxpayer in not implementing this option as the financial risk if a titleholder is not able to fulfil its decommissioning obligations is potentially significant, particularly given the nature, scale and cost of offshore petroleum operations.

Expanding the existing trailing provisions to create a larger dormant power that needs to be 'activated' by a decision of government, we understand may not need to be carried on the books of companies once an asset has been sold. In comparable jurisdictions who are managing maturing industry and given the last resort nature of trailing liability, it has been designed that trailing liability is 'activated' following a series of events and non-compliance by the current titleholder.

The department intends for a similar series of events or gateways, before trailing liability could be 'activated' by government, especially given this implementation option is to expand upon a form of existing trailing liability in the legislation, which currently has attached criminal liabilities with up to five years imprisonment should a breach occur.

The department is not aware of any instances in comparable jurisdictions where trailing liability has been required and it appears the threat of governments having the power has been sufficient to effect behavioural change in industry and increased diligence on who companies sell their assets to.

Option 3

Summary of regulatory impact calculations

Options	Technical and financial reporting Sector ($m)	Fit and proper person declaration and appropriateness criteria Sector ($m)	Change of ownership and control Sector ($m)	Total annual estimated regulatory costs ($m)	Total estimated regulatory costs over thirty years ($m)*
Option one:	0.645	-	-	0.644	19.350
Option three:	2.370	18.661	0.003	21.034	631.020
Change in regulatory costs	1.725	18.661	0.003	20.389	611.670

*A thirty-year period for forecasted regulatory costs has been used due to the extended duration of offshore oil and gas projects.

Option 3 (additional technical and financial reports): $1,895.66 (estimated cost for an organisation to prepare a report) based on 6 hours of time of a technical financial / administration employee at an hourly wage rate of $121.15 and 1 hour of time of 2 CEOs/Directors at a hourly wage rate of $583.33. $2,369,575.00 (estimated cost across the sector) based on a multiplier of 250 (estimated number of applications NOPTA will receive per FY) and 5 (average JV partners per title).

Option 3 (fit and proper associates test and appropriateness criteria application): $14,928.72 (estimated cost for an organisation to prepare an application) based on 2 hours of time of a technical financial / administration employee at an hourly wage rate of $121.15 and 1 hour of time of 12 CEOs/Directors at a hourly wage rate of $583.33 and an average of 2 associates per CEOs/Directors (24) with an average hourly cost of $320.24. $18,660,900.00 (estimated cost across the sector) based on a multiplier of 250 (estimated number of applications NOPTA will receive per FY) and 5 (average JV partners per title).

Option 3 (change of ownership and control application): $1,288.16 (estimated cost for an organisation to prepare an application) based on 1 hours of time of a technical financial / administration employee at an hourly wage rate of $121.15 and 1 hour of time of 2 CEOs/Directors at a hourly wage rate of $583.33. $2,576.32 across the sector with a multiplier of 2 (average number of applications NOPTA receives per FY).

Regulatory benefit

There is a regulatory benefit in amending the current framework and changing the focus of the regulator to implement a lower risk-tolerance approach to regulation of the offshore framework. The risks of an inappropriate titleholder entering the regime without the financial and technical capability to discharge their liabilities would be reduced. Option 3 provides the same regulatory benefits as Option 2.

Regulatory cost

There is a regulatory cost in being risk-averse in regulating the offshore industry. It would require significant resources from both the regulator to ensure compliance and also the titleholder, to comply with the requirements.

Intensive regulation is highly burdensome on the titleholder and is unlikely to yield any more regulatory benefit as taking the less burdensome risk-based approach. Furthermore, this regulatory approach is likely to deter investment from new potential titleholders in the Australian regime, thereby resulting in an opportunity cost.

Implementing this option could also stifle a company's cash flow which may negatively affect their financial health and result in the opposite outcome that it is trying to achieve i.e. forcing a company into insolvency and unable to meet their decommissioning liabilities.

Net benefit

Option 3 provides equal regulatory benefit as Option 2, however has significant additional regulatory impacts to industry, with little to no improvement to policy outcomes.

Other considerations

Option 3 includes the potential of stifling a company's cash flow, as companies must at all times carry the decommissioning liability in some form, despite selling its assets to another party.

Unlike Option 2, Option 3 would require companies to be potentially perpetually liable for liability costs of decommissioning, even after they no longer hold an interest in the title. Consultation with key industry stakeholders identified that this ongoing liability may significantly deter consideration to the selling and release of assets, which would negatively impact Australia's overall investment attractiveness. This consideration may also result in significantly less capital being available for companies to explore new investment opportunities across Australia and is likely to stimulate a change in industry behaviour in terms of the appetite of developing new oil and gas projects to meet Australia's future energy security needs.

While there is some regulatory benefit in reducing risks around decommissioning liabilities and appropriateness and capabilities of titleholders entering the regime, even the most intensive regulatory oversight cannot completely eliminate these risks. It is, instead, about trying to continuously improve the regulatory practices and reduce risks to as low as practicable while not stifling investment.

5. Consultation

Consultation with stakeholders on the proposed policies and measures has occurred in three key stages: engagement on the broader decommissioning framework as part of the department's Offshore Oil and Gas Decommissioning Review (the Decommissioning Review), the independent Review of the Circumstances that Led to the Administration of the Northern Oil and Gas Australia (NOGA) Group of Companies by Mr Steve Walker (the Walker Review) and a targeted workshop with industry through its peak body association, Australian Petroleum Production and Exploration Association (APPEA).

The Decommissioning Review

In October 2018 and prior to the liquidation of the NOGA group of companies, the department released a public discussion paper titled Decommissioning Offshore Petroleum Infrastructure in Commonwealth Waters, with submissions, workshops and consultation occurring throughout 2019.

The purpose of this consultation was to obtain feedback from relevant stakeholders to help ensure that Australia's decommissioning framework was fit for purpose, remains best practice, and positions Australia to respond to decommissioning challenges and opportunities now and into the future. The Decommissioning Review focused primarily on environmental and well integrity outcomes, as well as regulatory oversight.

The Decommissioning Review proposed that a titleholder's capacity to fulfil its obligations under a title, particularly its financial capacity for decommissioning, should be assessed at any time and/or as part of a change in parent company ownership or control of a corporate titleholder. Liability arrangements were also canvassed in the discussion paper.

Twenty three public submissions were received in response to the Discussion Paper. These came from a variety of sectors, entities and individuals including the offshore petroleum industry, environmental NGOs, fishing groups, academia, government and legal firms.

Feedback received as a result of this consultation identified that the current framework provided opportunities for:

greater government oversight when a change in the ownership or control occurs, and
expansion and strengthening of the policy principles that underpin financial assurance.

Of note, the agreed view is that current titleholders should be held responsible for decommissioning obligations, rather than the Australian taxpayer.

There was also specific feedback from oil and gas companies that only the current titleholder should be held responsible for decommissioning, rather than previous titleholders who are 'called back' in the event that the current titleholder is unable to fulfil their decommissioning obligations, otherwise known as 'trailing liability'.

While consultation on the Decommissioning Review was underway, the NOGA group of companies entered administration in October 2019 and went into liquidation on 7 February 2020. This further reinforced the need to improve the regulatory framework, to meet the new challenges presented by an industry which is ultimately moving towards decommissioning as it enters mid to late life in various titles and projects.

The Walker Review

In March 2020, the Minister for Resources, Water and Northern Australia, the Hon Keith Pitt MP, appointed Steve Walker to conduct the independent Review of the circumstances that led to the administration of the Northern Oil and Gas Australia group of companies. Mr Walker consulted with a wide range of stakeholders, which included key industry stakeholders and the regulators.

The purpose of this consultation was to obtain feedback as part of the review, which examined the roles, responsibilities and behaviours of key stakeholders and advised on potential reforms of the offshore oil and gas regulatory regime

The Walker Review made 9 recommendations to improve practices, policies and legislation. Notably, it recommended that:

The Decommissioning Review should consider recommending trailing liability, whereby a titleholder would be continually liable for the decommissioning and removal of its offshore assets, even after selling its interests in a title on to a different titleholder.
The Decommissioning Review should explore legislative changes or clarifications to enable the National Offshore Petroleum Titles Administrator (NOPTA), and the Joint Authorities to require titleholders to provide financial surety for their decommissioning liabilities, should NOPTA have concerns that the titleholder will not be in a position to meet such costs. Such sureties should be in a form that would be available to the Government in the case of the titleholder going into liquidation.
Regulatory concerns over the adequacy of legislation to allow NOPTA to have oversight of titleholder company level transactions, and to allow NOPTA to assess financial resource and technical qualification considerations before a title is transferred to an existing titleholder, should be resolved.
NOPTA's powers should be clarified so that it can obtain financial and technical capacity information about the titleholder, and thus monitor titleholder financial performance and technical capacity, throughout the tenure of the title, including decommissioning.
Consideration should be given to extending NOPTA's oversight to include the adequacy of titleholder corporate governance arrangements. In the meantime, NOPTA should consider updating the Offshore Petroleum Guideline: Transfer and Dealings Relating to Petroleum Titles to include an expanded section on titleholders' technical capacity and governance expectations.

Recommendations that go beyond the scope of the proposed amendments will be considered as part of the revised policy frameworks for decommissioning and safety.

Targeted industry consultation

The department has undertaken ongoing targeted consultation with the oil and gas industry through its peak body group, APPEA.

APPEA is the peak national body representing Australia's upstream oil and gas exploration and production industry. It has approximately 60 full member companies who account for an estimated 98 per cent of the Australia's petroleum production. APPEA also represents about 140 associate member companies that provide a wide range of goods and services to the upstream oil and gas industry.

On 19 October 2020, the department held a workshop with APPEA to discuss the proposed measures and obtain industry feedback.

During the consultation, APPEA's expressed the following views on behalf of its members:

Industry supports appropriate regulatory oversight at key gateways, including technical and financial information, to mitigate the risk of another NOGA-like event, but raised concerns about how some of these measures would be implemented. These concerns went to ensuring these measures do not impose unnecessary regulatory burden on industry, including by ensuring applicants are not required to provide information previously provided to government, and clarifying the gateways in which this information would be required or requested.
Trailing liability is not supported as a principle and should only be considered as an absolute last resort and considered in conjunction with a robust financial assurance regime. Industry's key concern is about the retrospectivity of a trailing liability measure and providing clarity about the point in time when the industry would be subject to such a measure.

The department received a detailed response to the proposed measures, and discussed the potential impacts that the proposed regulatory changes could have on industry. The objective of the department's consultation with APPEA was to obtain the views of those stakeholders who would be directly impacted by the regulatory changes as a result of the proposed measures.

Ongoing Consultation with NOPTA and the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA)

In addition to these three consultation processes, the department has also been regularly engaging with NOPTA and NOPSEMA as the administrator and regulator (respectively) of Australia's offshore oil and gas industry. NOPTA's purpose is to advise on, and administer, the Act in support of the effective regulation and management of our offshore petroleum resources, consistent with good oil field practice and optimum recovery.^{^[5]} NOPSEMA is the independent regulator for health and safety, structural (well) integrity and environmental management for all offshore oil and gas operations and greenhouse gas storage activities in Commonwealth waters, and in coastal waters where regulatory powers and functions have been conferred.^{^[6]}

The department has been undertaking these ongoing consultations to discuss issues such as regulatory options, implementation of potential measures and to inform the regulatory costings of the proposed changes. This consultation with NOPTA and NOPSEMA is instrumental to achieving a holistic understanding of the requirements of the regime and to ensure that the proposed measures are reasonable, achievable and measurable.

Areas of agreement and difference across the consultation process

Throughout the various consultations, the department received consistent feedback on a variety of issues relating to the current offshore regulatory framework and opportunities for improvement.

Importantly, while the Decommissioning Review and the administration/liquidation of the NOGA group of companies are separate issues, the Walker Review highlighted a number of challenges and opportunities for Australia.

Stakeholders the board agreed that titleholders, rather than the Australian taxpayer, should be responsible for their decommissioning obligations. Ensuring that current titleholders can be held responsible for their obligations under their titles serves the interests and mitigates the financial, safety and environmental risks to the industry, the Australian Government and the broader Australian community.

Similarly, stakeholders identified that the current framework should include greater regulatory oversight and clarity around the powers of the regulator, in order to seek out information relevant to the financial performance and technical capability of titleholders where there is a change of ownership and control of the titleholder.

A point of difference in views amongst those consulted included different positions on the proposed trailing liability measure. While the Walker Review recommended that a trailing liability measure be considered (whereby a titleholder would be continually liable for the decommissioning and removal of its offshore assets, even after selling its interests in a title on to a different titleholder), APPEA has advocated that its members do not support trailing liability as a principle, and should only be considered as an absolute last resort and considered in conjunction with a robust financial assurance regime.

The department notes that while this measure presents a potentially significant impost to industry, it remains an important 'backstop' where all other regulatory, legislative and operational levers have failed. Forms of trailing liability are a feature of other similar, reputable and mature offshore petroleum regimes, including Norway, the United Kingdom, the United States of America, and Canada, where the offshore oil and gas industry is successfully working under these regulatory requirements.

The Australian Government intends to exercise powers in respect to trailing liability where all other available options have failed. In its efforts to reduce the financial, safety and environmental risks within the offshore regulatory regime, the department considers that it would be remiss if it did not provide a 'last resort' safety mechanism to protect all parties from unforeseen events, including the industry itself, the government and the Australian taxpayer.

6. Preferred option

Feedback across the various consultation and review processes identified three consistent themes from a range of stakeholders.

Firstly, there was consensus amongst those consulted that the current regime could and should be improved to prevent, or significantly reduce, the risks of titleholders being unable to fulfil their obligations within the regime. Stakeholders identified that the offshore regime should allow for the responsible extraction of resources while also having proper regard to health, safety and environment and to ensure that the correct balance is struck, to maintain business confidence and encourage investment, in the Australian regime.

Secondly, there was consistent feedback that the decommissioning liabilities should be met by current titleholders as those who have derived economic benefits from the resources, rather than having these liabilities met by the Australian taxpayer. To that end, risks and responsibilities of titleholders operating within the Australian regime should be clearly allocated in the regulatory framework, ensuring that the regulatory expectations and requirements are clear to those intending to enter the regime.

Thirdly, and following on from the view that the regulatory framework required greater clarity, was the feedback that the current regime requires greater regulatory oversight and clarity around NOPTA's role and responsibilities, as well as their decision-making criteria and processes at key gateway points. Consultation showed that many stakeholders felt concerned about the unclear legislative provisions in the current regime, which limit the regulator's ability to obtain sufficient assurances and information at key gateways, that an applicant is suitable and capable to undertake petroleum activities within the regime.

After undertaking targeted consultation with relevant stakeholders and reviewing their feedback, the department recommends Option 2 in order to best address the problem statement. Option 2 delivers the greatest net benefit, as it ensures that the highest risk points (the entry points) within the regime, are mitigated to the extent possible (including the ability to call back a greater range of entities who not only installed offshore infrastructure property, but also derived an economic benefit from Australia's resources), while not creating unnecessary regulatory burden on industry and potentially discouraging investment. Greater clarity and regulatory oversight regarding decision making criteria, being a key concern of stakeholders, will be addressed by this option. Option 2 address the concerns of both the department and the oil and gas industry to ensure that entities entering or progressing through the regime are suitable, financially and technically capable to undertake petroleum activities in a safe and environmentally sustainable manner, and do not have a history of material non-compliance, fraudulent or misleading behaviour and/or financial mismanagement. Option 2 also provides the government with a last resort safety mechanism - trailing liability, to call back a greater range of entities who derived an economic benefit from Australia's resources, in order to mitigate the risks to the Australian taxpayer, where all other safeguards have failed.

By comparison, under Option 1, there is no change to the regulatory framework which continues to operate in its current form. While it will continue to provide a strong and effective framework that industry is familiar with, it does not provide greater assurances at key gateway points to mitigate the risk that companies entering the regime may be unable to meet their obligations. This in turn, may result in a similar incident to that of the NOGA group of companies where significant liabilities fall to industry and the Australian taxpayer. Unlike Option 2 (the recommended option), Option 1 does not increase regulatory oversight, or provide greater assurance particularly at high risk gateways, that a titleholder is suitable to enter the Australian offshore regime and undertake petroleum activities.

Option 3 provides a far more intensive approach to regulating industry, without a material net benefit in achieving the intended policy outcome. Option 3 is likely to deter investment from new titleholders in the Australian regime due to its onerous measures and does not address stakeholder concerns raised during consultation regarding striking the right balance between risk management, responsible resource extraction and encouraging investment in the Australian regime. Option 3 provides higher regulatory impacts with little to no improvement to policy outcomes of Option 2.

As Option 2 addresses the problem statement by avoiding the additional anticipated regulatory impacts as Option 3, Option 2 is the preferred option.

In recommending Option 2, one key consideration in the decision-making process was the feedback received during consultation on trailing liability. The department noted that trailing liability was not supported by the oil and gas industry, and in order to ensure that this measure is effective but not overly burdensome on titleholders, the department has chosen Option 2 which speaks to a risk-based approach, as opposed to an intensive regulatory approach.

Rather than proposing a trailing liability measure, which is a 'standing obligation' in Option 3, the department is recommending expansion to the existing powers to issue Directions under Option 2. Under this measure it is in the event that a current titleholder cannot meet its decommissioning obligations and other safeguards have failed, that previous titleholders and/or related persons (including a parent company) may be called back to meet these obligations. Under a 'standing obligation' measure (Option 3), companies would be required to maintain the financial capacity to decommission all infrastructure previously held and managed, indefinitely, or until such infrastructure is successfully decommissioned.

One area of uncertainty in considering all options were the costing assumptions that the department relied upon. In order to accurately estimate both the cost of implementing the regulatory changes as well as the potential costs of decommissioning various projects, the department obtained industry-reflective decommissioning costs through consultation with the National Energy Resources Australia (NERA).

The cost of the proposed regulatory changes in Option 2 are minimal in comparison to the risk of potential decommissioning liabilities of offshore oil and gas assets and infrastructure, where titleholders are unable to meet their obligations. The estimated cost increased associated with implementing the proposed changes in Option 2 is approximately AUD$3.33 million per year. By comparison, the decommissioning cost for a range of offshore activities are estimated as follows:

plugging and abandonment of a single offshore exploration or appraisal well can range between USD$9 million to USD$32 million (approximately AUD$12.7 million to AUD$45.4 million)^{^[7]}
decommissioning a medium sized project with a single semi-submersible or jack-up platform with no shared infrastructure and fewer than 10 wells could range from US$255 million to $US350 million
decommissioning a large, multiple platform project with shared infrastructure and more than 25 wells could range from US$840 million to US$1.8 billion, or more

These estimated costs are highly variable, will vary between projects, and do not represent a possible minimum or maximums. Rather they illustrate the range of costs that can reasonably be expected^{^[8]}. This shows that the cost of implementing the proposed regulatory changes under
Option 2 are minor in comparison.

The department is committed to working with relevant stakeholders to improve the regulatory framework and ensure beneficial outcomes to all stakeholders, including industry and the Australian community. Continuous improvement of the offshore regulatory framework will maintain community confidence in the regime and provide for better regulatory outcomes for both the government and the industry.

The department does not consider that these measures will result in a significant burden on industry and in fact, believes that Option 2 will benefit the offshore oil and gas industry, as improved regulatory practices will increase community confidence and provide greater assurances to the Australian community. In addition, all stakeholders will benefit from a reduction in the financial, environmental and safety risks where a titleholder is unable to meet their decommissioning obligations.

7. Implementation

The Australian offshore oil and regime is a well-established regulatory framework that has evolved to be mature, reliable and dynamic. The Australian Government reviews and updates the framework, to ensure that the regime remains fit for purpose to meet future challenges while also encouraging investment. It is through this lens, that the proposed changes to the regulatory framework are considered by the department to be 'business as usual', in its efforts to continuously improve the offshore regime.

The timeframes in delivering and implementing Option 2 will be based on the proposed measures being passed as a legislative bill, expected to be introduced into parliament in early 2021.

Australia has a relatively mature offshore oil and gas industry, which includes many large-scale operators, with significant experience across a range of jurisdictions. The oil and gas industry is well-versed in implementing regulatory change and the department is confident that industry will be able to adapt to the changes.

To ensure that key stakeholders such as the oil and gas industry are informed of the regulatory changes, the department and the regulators are committed to engaging early, efficiently and continuously. The department, NOPTA and NOPSEMA are also liaising with key stakeholder organisations such as APPEA, to ensure that any new regulatory changes are communicated through appropriate channels, to capture smaller operators who may not be aware of the changes. The department, NOPTA and NOPSEMA will also publish new policy and regulatory guidelines on their websites to ensure that appropriate guidance information is easily accessible to all interested stakeholders.

Option 2 will be evaluated and monitored in a variety of ways. Most notably, the department and the regulators will be able to determine its success if applications are, in fact, received in accordance with new regulatory requirements such as change of control and ownership of titleholders. Additionally, the regulators will get an insight into whether the regulatory changes have been adequately communicated to the industry, based on the level of guidance that they may be required to provide to companies submitting their applications. Similarly, the regulators may gauge how well the oil and gas industry understand the proposed measures based on how much additional information they may seek from applicants seeking to enter the regime.

A table of the key implementation risks of Option 2 is at Annex 2.

Ultimately, as a long-term evaluation of whether Option 2 was successful in addressing the problem statement, the department will consider how many (if any) titleholders are unable to meet their obligations over the next ten, twenty and thirty years. Noting that while it is impossible to completely eliminate the risk of this occurring, consideration can be given to both the number and nature of future situations in which a titleholder is unable to meet its obligations under its title. The department intends to continuously review and improve the offshore regulatory framework, to ensure that these risks are reduced to as low as reasonably practicable.
Annex 1: Costing Assumptions

Average joint venture (JV) partners per title - 5 (based on NOPTA Titleholder Reports Jun 17 - Feb 20)
Number of stakeholders impacted by the measures - 185 (based on total number of titleholders and a change rate of 8 new organisations per financial year (FY) from NOPTA Titleholder Reports Jun 17 - Feb 20)
Wage rate band of offshore oil and gas companies technical financial / administration employees: $120 - $150k (inclusive of overheads and on-costs) - averaged to $135k per annum / $121.15 hourly (based on reported average industry wage rates)
Wage rate band of CEOs/Directors of offshore oil and gas companies: $500 - $800k (inclusive of overheads and on-costs) - averaged to $650k per annum/$583.33 hourly (based on reported average industry wage rates)
Average number of directors of offshore oil and gas companies - 12 (based on reported average industry information)
Average time for a single organisation to undertake requirements (based on NOPTA advice):

A technical and financial report application - 6 hours for 1 technical financial / administration employee to source and compile information, 1 hour for 2 directors required to execute application.
A fit and proper person declaration and appropriateness criteria application - 2 hours for 1 technical financial / administration employee to liaise and compile information, 1 hour for 1 director required to execute declaration.
A change of ownership and control application - 1 hour for 1 technical financial / administration employee to source and compile information, 1 hour for 2 directors required to execute application.

Average number of applications NOPTA currently receives requiring technical and financial report applications - 68 per year (based on NOPTA advice)
Estimated number of applications NOPTA would receive requiring technical and financial reports under Option 2 - 87 per year (based on NOPTA advice)
Estimated number of applications NOPTA would receive requiring technical and financial reports under Option 3 - 250 per year (based on NOPTA advice)
Estimated number of applications NOPTA would receive fit and proper person declaration and appropriateness criteria under Option 2 - 87 per year (based on NOPTA advice)
Estimated number of associates NOPTA would require fit and proper person declaration and appropriateness criteria to be completed under Option 3 - 2 per CEOs/Directors of offshore oil and gas companies with an average hourly cost of $320.24.
Estimated number of change of ownership and control applications NOPTA would receive under Option 2 and 3 - 2 per year (based on NOPTA Change of Titleholder Company Name Report average Nov 18 - Jul 20).

Annex 2: Table of Key Implementation Risks

Risk	Consequences	Management and Mitigation	Likelihood
There are implementation overlaps and/or gaps between the roles and responsibilities of the department, NOPTA and NOPSEMA once regulatory amendments take effect.	Major - There are gaps in regulatory oversight that may result in financial risks not being mitigated. Minor - Duplication of duties results in additional regulatory burden on the department, NOPTA or NOPSEMA as well as industry.	Ongoing and early engagement between the department, NOPTA and NOPSEMA to ensure all parties are clear on their role and responsibilities in implementing the regulatory changes.	Low
Regulatory/policy guidance material and internal systems and processes are not amended or updated before measures are implemented.	Minor - Companies will be unable to find appropriate guidance material as to how the measures will be implemented and may not comply with new requirements.	To mitigate this risk, the department is committed to working with the NOPTA and NOPSEMA in order to ensure that all policy and regulatory guidance materials are updated prior to implementation, to reflect changes in the regulatory framework and explain the policy and operation and effects of such changes.	Low
Changes to the regulatory framework are not implemented by NOPTA and/or NOPSEMA.	Major - The regulatory framework is not improved and risk of unsuitable entrants entering into the offshore regime at key gateways is not mitigated and the Australian taxpayer may be left to meet significant financial liabilities.	The department will liaise regularly with NOPTA and NOPSEMA to ensure that they have all the information and assistance that they require to administer these measures to meet the policy objectives.	Low

[1] Department of Industry, Science, Energy and Resources, Commonwealth of Australia Resources and Energy Quarterly September 2020, p 67.

[2] Estimated by Wood Mackenzie and assumes all infrastructure will be removed with no life extension activities.

[3] Estimated by Wood Mackenzie and assumes all infrastructure will be removed with no life extension activities.

[4] Estimated by Wood Mackenzie and assumes all infrastructure will be removed with no life extension activities.

[7] Estimated costs of decommissioning were obtained from NERA and are industry-reflective. Costs will depend on the size, scope and complexity of operations.

[8] Estimated costs of decommissioning were obtained from NERA and are industry-reflective. Costs will depend on the size, scope and complexity of operations.

Commonwealth Numbered Regulations - Explanatory Statements